<PAGE>
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               SECURITIES AND EXCHANGE COMMISSION
                     Washington, D.C. 20549
 
                           FORM 10-K
 
 (Mark One)
 
     (X)  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
          EXCHANGE ACT OF 1934 (FEE REQUIRED)
          For the fiscal year ended December 31, 1995
                               OR
     ( )  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
          SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
          For the transition period from          to
 
                 Commission file number 1-3183
 
                      ENSERCH CORPORATION
 
            Texas                                75-0399066
   (State or other jurisdiction               (I.R.S. Employer
 of incorporation or organization)           Identification No.)
 
          ENSERCH Center
     300 South St. Paul Street
           Dallas, Texas                              75201-5598
 (Address of principal executive office)              (Zip Code)
 
 Registrant's Telephone Number, Including Area Code - (214) 651-8700
 
  SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
 
                                        Name of Each Exchange
     Title of Each Class                on which Registered
     -------------------                ---------------------
 
 Common Stock ($4.45 par value)         New York Stock Exchange
                                        Chicago Stock Exchange
                                        London Stock Exchange
 
 Preferred Stock (no par value):
    Depositary Preferred Shares,         New York Stock Exchange
       Series E (each representing
       1/10 share of the Adjustable
       Rate Cumulative Preferred Stock,
       Series E)
    Depositary Preferred Shares,          New York Stock Exchange
       Series F (each representing
       1/40 share of the Adjustable
       Rate Cumulative Preferred Stock,
       Series F) (liquidation preference
       $1,000 per share)
 
 SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
 
     Indicate by check mark whether Registrant (1) has filed all reports
 required to be filed by Section 13 or 15(d) of the Securities Exchange Act
 of 1934 during the preceding twelve months (or for such shorter period that
 the Registrant was required to file such reports) and (2) has been subject
 to such filing requirements for the past 90 days. Yes (X) No ( )
 
     Aggregate market value of the voting stock held by nonaffiliates of
 the Registrant as of March 15, 1996: $1,024,994,880.
 
     Shares of the Registrant's Common Stock outstanding as of March 15,
 1996: 68,626,602 shares.
 
     Documents incorporated by reference and the Part of the Form 10-K
 into which the document is incorporated: Proxy Statement filed on or about
 March 29, 1996 (Part III).
 
     Indicate by check mark if disclosure of delinquent filers pursuant to
 Item 405 of Regulation S-K is not contained herein, and will not be
 contained, to the best of Registrant's knowledge, in definitive proxy or
 information statements incorporated by reference in Part III of this Form
 10-K or any amendment to this Form 10-K. (X)
 
 ===========================================================================
 
  <PAGE>
<PAGE>
 
                           FORM 10-K
                         ANNUAL REPORT
          For the Fiscal Year Ended December 31, 1995
               
                       TABLE OF CONTENTS
 
 <TABLE>
 <CAPTION>
 
                                                           Page
                             PART I
 <S>       <C>                                              <C>
 ITEM 1.   Business. . . . . . . . . . . . . . . . . . . . . 1 
           Business Segments . . . . . . . . . . . . . . . . 1 
           Natural Gas and Oil Exploration and Production. . 1 
               General . . . . . . . . . . . . . . . . . . . 1 
               Reorganization. . . . . . . . . . . . . . . . 1 
               Recent Developments . . . . . . . . . . . . . 2 
                   DALEN Acquisition . . . . . . . . . . . . 2 
                   EEX Common Stock Offering . . . . . . . . 2 
                   Garden Banks Project. . . . . . . . . . . 2 
                   Green Canyon Project. . . . . . . . . . . 3 
                   Rocky Mountain Properties . . . . . . . . 3 
                   International Operations. . . . . . . . . 3 
               Sales Information . . . . . . . . . . . . . . 4 
               Major Customers . . . . . . . . . . . . . . . 4 
               Competition . . . . . . . . . . . . . . . . . 4 
               Government Regulation4  . . . . . . . . . . . . 
                   Environmental Matters . . . . . . . . . . 4 
                   Other Laws and Regulations. . . . . . . . 6 
           Natural Gas Pipeline & GPM. . . . . . . . . . . . 6 
               Pipeline. . . . . . . . . . . . . . . . . . . 6 
               Gathering and Processing. . . . . . . . . . . 7 
               Gas Marketing . . . . . . . . . . . . . . . . 7 
               Competition . . . . . . . . . . . . . . . . . 8 
               Regulation. . . . . . . . . . . . . . . . . . 8 
           Natural Gas Distribution. . . . . . . . . . . . . 8 
               Competition . . . . . . . . . . . . . . . . . 9 
               Source and Availability of Raw Materials. . . 9 
               Regulation. . . . . . . . . . . . . . . . . .10 
           Power . . . . . . . . . . . . . . . . . . . . . .11 
           Clean Air Act . . . . . . . . . . . . . . . . . .12 
           Patents and Licenses. . . . . . . . . . . . . . .13 
           Employees . . . . . . . . . . . . . . . . . . . .13 
           Executive Officers of Registrant. . . . . . . . .13 
 ITEM 2.   Properties. . . . . . . . . . . . . . . . . . . .14 
 ITEM 3.   Legal Proceedings . . . . . . . . . . . . . . . .17 
 ITEM 4.   Submission of Matters to a Vote of Security Holders17 
 
                            PART II
 
 ITEM 5.   Market for Registrant's Common Equity and Related
            Stockholder Matters.. . .. . . . . . . . . . . .17 
 ITEM 6.   Selected Financial Data . . . . . . . . . . . . .17 
 ITEM 7.   Management's Discussion and Analysis of Financial
            Condition and Results of Operations. . . . . . .17 
 ITEM 8.   Financial Statements and Supplementary Data . . .18 
 ITEM 9.   Changes in and Disagreements with Accountants on
            Accounting and Financial Disclosure. . . . . . .18 
 
 
                            PART III
 
 ITEM 10.  Directors and Executive Officers of the Registrant18 
 ITEM 11.  Executive Compensation. . . . . . . . . . . . . .18 
 ITEM 12.  Security Ownership of Certain Beneficial Owners
            and Management . . . . . . . . . . . . . . . . .18 
 ITEM 13.  Certain Relationships and Related Transactions. .18 
 
                            PART IV
 
 ITEM 14.  Exhibits, Financial Statement Schedules and Reports on
            Form 8-K . . . . . . . . . . . . . . . . . . . .18 
 APPENDIX A Financial Information. . . . . . . . . . . . . A-1 
 
 </TABLE>
 
 <PAGE>
<PAGE>
 
 ITEM 1.  Business
 
     ENSERCH Corporation ("ENSERCH" or the "Corporation") is an integrated
 company focused on natural gas.  It is the successor to a company organized
 in 1909 for the purpose of providing natural-gas service to North Texas.
 The Corporation's operations include the following:
 
     -    Natural Gas and Oil Exploration and Production - Exploring for,
          developing, producing and marketing natural gas and oil.
          (Enserch Exploration, Inc. [83.4% owned] and related
          operations.)
 
     -    Natural Gas Pipeline & Gathering, Processing and Marketing
          (GPM) - Owning and operating interconnected natural-gas
          transmission lines, underground storage reservoirs, compressor
          stations and related properties, all within Texas; gathering
          and processing natural gas to remove impurities and extract
          liquid hydrocarbons for sale; and the wholesale and retail
          marketing of natural gas in several areas of the U.S. (Lone
          Star Pipeline Company, a division of the Corporation, Enserch
          Processing Company, a division of the Corporation, Enserch
          Processing, Inc., Enserch Energy Services, Inc., DGS Holdings
          Corp. and related operations.)
 
     -    Natural Gas Distribution - Owning and operating some 550 local
          gas utility distribution systems in Texas.  (Lone Star Gas
          Company, a division of the Corporation, and related
          operations.)
 
     -    Power and Other - Developing, financing and operating electric-
          power generating plants and cogeneration facilities and
          operating thermal-energy plants for large building complexes,
          such as universities and medical centers.  (Enserch Development
          Corporation, Lone Star Energy Company and related operations.)
 
 BUSINESS SEGMENTS
 
     Financial information required hereunder is set forth under "Summary
 of Business Segments" included in Appendix A to this report.
 
 NATURAL GAS AND OIL EXPLORATION AND PRODUCTION
 
 General
 
     Enserch Exploration, Inc. ("EEX"), an 83.4% owned subsidiary of
 ENSERCH, has been engaged in the exploration for and the development,
 production and sale of natural gas and crude oil since 1918.  EEX is one of
 the largest independent exploration and production companies in the United
 States, with a reserve base of 1,792 billion cubic feet of natural gas
 equivalent ("Bcfe") at January 1, 1996, as estimated by DeGolyer and
 MacNaughton ("D&M"), independent petroleum consultants.  Approximately 75%
 of these reserves consist of natural gas.  EEX has grown through
 exploration, development and acquisition activities concentrated in major
 production basins located offshore in the Gulf of Mexico and onshore in
 East Texas, North Central Texas and the U.S. Gulf Coast.
 
 Reorganization
 
     EEX's gas and oil operations represent the gas and oil exploration
 and production business of ENSERCH.  From 1985 through December 30, 1994,
 this business was conducted primarily through Enserch Exploration Partners,
 Ltd. ("EP"), a limited partnership in which a minority interest (less than
 1% since 1989), was held by the public.  At year-end 1994, pursuant to a
 plan for the reorganization of EP ("Reorganization"), EEX acquired, through
 a series of transactions, all of the operating properties of EP Operating
 Limited Partnership ("EPO"), EP's 99%-owned operating partnership, in
 exchange for shares of EEX common stock.  On December 30, 1994, the
 Reorganization was consummated, EPO was merged into EEX, EP was liquidated
 and the EEX common stock held by EP was distributed to EP's limited and
 general partners in accordance with their partnership interests.
 
     Upon the liquidation of EP and distribution of EEX common stock,
 public unitholders of EP received 805,914 shares (.8%) and ENSERCH received
 103,775,328 shares (99.2%) of EEX's 104,581,242 shares then outstanding. 
 Trading of EEX common stock began on the New York Stock Exchange under the
 symbol "EEX" on January 3, 1995.
 
     In 1995, EEX acquired ENSERCH's international and SACROC operations.
 
 Recent Developments
 
     DALEN Acquisition.  On June 8, 1995, EEX acquired all of the capital
 stock of DALEN Corporation ("DALEN"), an independent gas and oil company
 engaged in the exploration for and the development and production of
 natural gas and crude oil (the "DALEN Acquisition").  Through the DALEN
 Acquisition, EEX acquired proved reserves totaling 397 Bcfe at June 30,
 1995, and other assets for cash of $340 million and assumed DALEN's bank
 debt of $115 million.  The DALEN Acquisition was initially funded through
 EEX's borrowings.  DALEN's activities are oriented primarily toward natural
 gas and are concentrated in selected major production regions, including
 the Gulf Coast, the Gulf of Mexico and the Mid-Continent.
 
     EEX Common Stock Offering.  On September 26, 1995, EEX sold 20
 million shares of its common stock to the public for net proceeds of
 approximately $208 million after expenses, and ENSERCH's ownership was
 reduced to 83.4%.  Proceeds from the sale were used to reduce borrowings
 incurred to finance the DALEN Acquisition.
 
     Garden Banks Project.  In the third quarter of 1995, an affiliate of
 Mobil Corporation ("Mobil") acquired a 40% working interest in EEX's Garden
 Banks Block 388 project, a six-block unit located 200 miles southwest of
 New Orleans, Louisiana, in 2,200 feet of water.  EEX received cash,
 property interests and future work commitments on the project.  In
 addition, EEX was relieved of capital and operating lease obligations of
 approximately $140 million as well as 40% of the capital expenditures
 required to complete the project.  EEX now owns a 60% working interest and
 remains the operator of the project.  
 
     To date, two wells that had been drilled and completed prior to the
 facility moving in are producing on Block 388, and a third well, which is
 in progress, is expected to begin producing in the second quarter of 1996. 
 Two wells have been drilled on adjacent Block 387 and are planned for
 subsea completion and tie-back to the production facility, which will allow
 production to commence during the second quarter of 1996.  EEX plans to
 drill and complete a fourth well from the platform in 1996, bringing to six
 the number of wells producing by year-end.
 
     In January 1996, the combined flow rate from two wells previously
 drilled on Block 388 was equivalent to 4,000 barrels ("Bbls") of oil per
 day, down from the initial production rate, which was the equivalent of
 approximately 9,000 Bbls of oil per day.  While a decline in daily
 production from the initial rate is normal, the magnitude of the decline is
 being carefully evaluated.  Development plans, which may include water-
 injection wells, will be dictated by characteristics of formations and
 reservoirs, including flow rates and declines, which become better defined
 with each additional well and each additional month of operation.  Gross
 proved reserves attributed thus far to this project by D&M at the beginning
 of 1996 were equivalent to 39 million barrels ("MMBbls") of oil.
 
     On September 13, 1995, EEX, together with Mobil, submitted the
 highest bids and was awarded exploration and development rights on ten
 additional blocks in the Garden Banks area.
 
     Green Canyon Project.  In October 1995, another affiliate of Mobil
 and an affiliate of Reading & Bates Corp.  purchased a 40% and 20% working
 interest, respectively, in EEX's Green Canyon Block 254 project, a four-block 
 unit located approximately 150 miles south of New Orleans, Louisiana,
 in 2,200 to 3,400 feet of water.  EEX received cash, an interest in a gas
 and oil property and future work commitments.  EEX now owns a 40% working
 interest and remains the operator of the project.  
 
     Gross proved reserves attributed to this project thus far by D&M are
 equivalent to nearly 72 MMBbls of oil, and work continues to further
 delineate the extent of identified hydrocarbon-bearing formations.  The
 reserves are based on two wells and one sidetrack drilled prior to 1995 on
 Block 254 and a third productive well drilled in late 1995 which flowed at
 a rate equivalent to 3,000 Bbls of oil per day on a limited test.  The next
 confirmation well is being drilled on Block 298 and is planned to bottom on
 Block 297 at 17,500 feet.  The well, if successful, will extend the field
 limits 3,000 feet to the south and add additional proved reserves. 
 Simultaneously, EEX and its partners are reviewing potential production
 alternatives that are expected to lead to the ultimate design and sizing of
 a production facility.  Tentatively, the group is examining the merits of a
 floating facility capable of handling the equivalent of 70,000 Bbls of oil
 per day with wells connected by subsea templates and bundled flow lines. 
 First production is expected from Green Canyon in 1999.
 
     On May 10, 1995, EEX, on behalf of its Green Canyon partners,
 submitted the highest bids and was awarded seven additional blocks located
 within ten miles of this project.
 
     Rocky Mountain Properties.  In December 1995, EEX announced plans to
 offer for sale its Rocky Mountain area properties, which are in six states,
 aggregate over 250,000 net acres and had proved reserves of 169 Bcfe at
 January 1, 1996.  These properties were mostly acquired as part of the
 DALEN Acquisition and are not within the core area of EEX's other
 properties.  See "Financial Review - Natural Gas and Oil Exploration and
 Production" in Appendix A.
 
     International Operations.  In 1995, EEX acquired the international
 gas and oil operations of ENSERCH in exchange for 1,240,000 shares of EEX
 common stock and $2.6 million in cash.  The acquired operations consist of
 concessions in Indonesia, Malaysia and Israel and had proved reserves of
 5 MMBbls of oil at January 1, 1996, all on the Indonesian properties.  EEX
 had previously managed these properties for ENSERCH.  In 1995, EEX
 announced the conclusion of a Memorandum of Understanding to form a joint
 venture with ONGC Videsh Ltd., a wholly owned subsidiary of The Oil and
 Natural Gas Corporation of New Delhi, India, to explore and develop
 hydrocarbon resources in India and other countries.
 
 Sales Information
 
     Sales data are set forth under "Natural Gas and Oil Exploration and
 Production Operating Data" included in Appendix A to this report.
 
 Major Customers
 
     EEX sells its gas and oil under long- and short-term contracts.  In
 1995, Enserch Energy Services, Inc. ("EES"), the ENSERCH natural-gas
 marketing subsidiary, was EEX's largest gas customer, purchasing gas under
 two long-term variable-priced contracts.  A division of ENSERCH, Lone Star
 Gas Company, purchases gas under a long-term fixed-priced service contract. 
 In 1995, approximately 10% of EEX's natural-gas volumes was sold to Lone
 Star Gas Company.  The continuing maturity of gas markets is causing an
 evolution in the gas marketing efforts of EEX.  Unbundling of services by
 interstate pipelines, deregulation efforts of many state regulatory bodies
 and the explosion of financial instruments tied to gas markets have
 radically altered marketing opportunities for producers.  EEX has concluded
 that it can achieve the greatest economic benefit from using the services
 of gas marketing organizations rather than having its own large staff,
 while maintaining a core staff to ensure market prices are being received.
 
     Oil sales contracts are for one year or less, and prices generally
 are based upon field posted prices plus negotiated bonuses.
 
     EEX may utilize futures contracts, commodity price swaps and other
 financial instruments to reduce exposure of EEX's gas and oil production to
 price volatility.  See "Financial Review - Natural Gas and Oil Exploration
 and Production" and Note 6 of the Notes to Consolidated Financial
 Statements included in Appendix A for additional information on hedging
 activities.
 
 Competition
 
     All phases of the gas and oil industry are highly competitive.  EEX
 competes in the acquisition of properties, the search for and development
 of reserves, the production and sale of gas and oil and the securing of the
 labor and equipment required to conduct operations.  EEX's competitors
 include major gas and oil companies, other independent gas and oil concerns
 and individual producers and operators.  Many of these competitors have
 financial and other resources that substantially exceed those available to
 EEX.  Gas and oil producers also compete with other industries that supply
 energy and fuel.
 
 Government Regulation
 
     The gas and oil industry is extensively regulated by federal, state
 and local authorities.  Legislation affecting the gas and oil industry is
 under constant review for amendment or expansion.  Numerous departments and
 agencies, both federal and state, have issued rules and regulations binding
 on the gas and oil industry and its individual members, some of which carry
 substantial penalties for the failure to comply.  Inasmuch as such laws and
 regulations are frequently amended, reinterpreted or expanded, EEX is
 unable to predict the future cost or impact of complying with such laws and
 regulations.
 
     The Railroad Commission of Texas ("RRC") regulates the production of
 natural gas and oil by EEX in Texas.  Similar regulations are in effect in
 all states in which EEX explores for and produces natural gas and oil. 
 These regulations generally require permits for the drilling of gas and oil
 wells and regulate the spacing of the wells, the prevention of waste, the
 rate of production and the prevention and cleanup of pollution and other
 materials.
 
     Environmental Matters.  Gas and oil operations are subject to
 extensive federal, state and local laws and regulations, including the
 Comprehensive Environmental Response, Compensation and Liability Act
 ("CERCLA"), also known as the "Superfund Law", and similar state statutes
 and, with respect to federal leases, to interruption or termination by
 governmental authorities on account of environmental and other
 considerations.  Regulations of the Department of the Interior currently
 impose absolute liability upon the lessee under a federal lease for the
 costs of clean-up of pollution resulting from a lessee's operations, and
 such lessee may also be subject to possible legal liability for pollution
 damages.  EEX maintains insurance against costs of clean-up operations but
 is not fully insured against all such risks.  A serious incident of
 pollution may result in the Department of the Interior requiring lessees
 under federal leases to suspend or cease operation in the affected area. 
 With respect to any EEX operations conducted on offshore federal leases,
 liability may generally be imposed under the Outer Continental Shelf Lands
 Act for costs of clean-up and damages caused by pollution resulting from
 such operations, other than damages caused by acts of war or the negligence
 of third parties.
 
     The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
 impose a variety of regulations on "responsible parties" (which includes
 owners and operators of offshore facilities) related to the prevention of
 oil spills and liability for damages resulting from such spills in the
 United States waters.  In addition, it imposes ongoing requirements on
 responsible parties, including proof of financial responsibility to cover
 at least some costs in a potential spill.  On August 25, 1993, the Minerals
 Management Service (the "MMS"), a federal agency, published an advance
 notice of its intention to adopt a rule under the OPA that would require
 owners and operators of offshore gas and oil facilities to establish
 $150 million in financial responsibility.  Under the proposed rule,
 financial responsibility could be established through insurance, guaranty,
 indemnity, surety bond, letter of credit, qualification as a self-insurer
 or a combination thereof.  There is substantial uncertainty as to whether
 insurance companies or underwriters will be willing to provide coverage
 under the OPA because the statute provides for direct lawsuits against
 insurers who provide financial responsibility coverage, and most insurers
 have strongly protested this requirement.  The financial tests or other
 criteria that will be used to judge self-insurance are also uncertain.  EEX
 cannot predict the final form of the financial responsibility rule that
 will be adopted by the MMS, but such rule has the potential to result in
 the imposition of substantial additional annual costs on EEX and otherwise
 materially adversely affect EEX.  The impact of the rule, however, should
 not be any more adverse to EEX than it would be to other similarly situated
 owners or operators in the Gulf of Mexico.
 
     The operations of EEX are also subject to the Clean Water Act and the
 Clean Air Act, as amended, and comparable state statutes.  The EPA is
 currently implementing regulations pursuant to the Clean Air Act, and the
 states are also implementing programs.  EEX may be required to incur
 certain capital expenditures over the next five to ten years for air
 pollution control equipment.
 
     EEX's onshore operations are subject to numerous United States
 federal, state and local laws and regulations controlling the discharge of
 materials into the environment or otherwise relating to the protection of
 the environment, including CERCLA.  Such regulations, among other things,
 impose absolute liability on the lessee under a lease for the cost of
 clean-up of pollution resulting from a lessee's operations, subject the
 lessee to liability for pollution damages, may require suspension or
 cessation of operations in affected areas and impose restrictions on the
 injection of liquids into subsurface aquifers that may contaminate
 groundwater.  Persons who are or were responsible for releases of hazardous
 substances under CERCLA may be subject to joint and several liability for
 the remediation and clean-up costs and for damages to natural resources. 
 EEX has received inquiries regarding and could be named as a potentially
 responsible party at two Superfund sites.  However, EEX does not believe
 that any liabilities in connection with such matters will have a material
 adverse effect on its business or results of operations.
 
     For offshore operations, lessees must obtain the MMS and various
 other federal and state agencies' approval for exploration, development and
 production plans prior to the commencement of such operations.  Similarly,
 the MMS has promulgated other regulations governing the plugging and
 abandoning of wells located offshore and the removal of all production
 facilities.  Under certain circumstances, including but not limited to,
 conditions deemed to be a threat or harm to the environment, the MMS may
 also require any EEX operation on federal leases to be suspended or
 terminated in the affected area.
 
     Other Laws and Regulations.  Various laws and regulations require
 permits for drilling wells and the maintenance of bonding requirements in
 order to drill or operate wells and also regulate the spacing and location
 of wells, the method of drilling and casing wells, the surface use and
 restoration of properties upon which wells are drilled, the plugging and
 abandoning of wells, the prevention of waste of gas and oil, the prevention
 and cleanup of pollutants, the maintenance of certain gas/oil ratios and
 other matters.  EEX's operations are also subject to various conservation
 requirements.  These include the regulation of the size and shape of
 drilling and spacing units or proration units, the density of wells which
 may be drilled, maximum rates of production and unitization or pooling of
 oil and gas properties.
 
     In the aggregate, compliance with federal and state rules and
 regulations is not expected to have a material adverse effect on EEX's
 operations.
 
 NATURAL GAS PIPELINE & GPM
 
     The Corporation's pipeline and GPM business is comprised of the
 partially rate-regulated business of Lone Star Pipeline Company ("LSP"),
 the nonregulated gathering and gas processing operations of Enserch
 Processing Company("EPC") and the nonregulated gas marketing operations of
 Enserch Energy Services, Inc. ("EES").  Operating data for this segment are
 set forth under "Natural Gas Pipeline & Gathering, Processing and Marketing
 Operating Data" included in Appendix A to this report.
 
     Pipeline.  LSP owns and operates interconnected natural-gas
 transmission lines, underground gas storage reservoirs, compressor stations
 and related properties, all within Texas.  Through these facilities, it
 transports natural gas to the distribution systems of Lone Star Gas Company
 ("LSG").  Rates for these services are regulated by the RRC.  LSP also
 transports natural gas for affiliates other than LSG and third-party
 shippers.  LSP's transmission system is connected to the major gas hubs at
 Waha in West Texas, Katy in South Texas and Carthage in East Texas.
 
     For the year ended December 31, 1995, 23% of total LSP throughput
 represented volumes transported to LSG for ultimate sale to residential and
 commercial customers, 38% represented volumes transported for ultimate
 destination to competitive on-system industrial and power-generation
 markets and 39% represented volumes transported for destination to off-
 system markets.
 
     Revenues from transporting gas for LSG are influenced by seasonal
 temperature variations.  The majority of LSG's residential and commercial
 gas customers use gas for heating and their needs are directly affected by
 the mildness or severity of the heating season.  Deliveries to
 electric-generation customers are affected by the mildness or severity of
 both cooling and heating seasons.
 
     The Corporation holds a 50% interest in a partnership named Gulf
 Coast Natural Gas Company, which operates a transmission system in the
 Texas Gulf Coast area that transports and sells natural gas primarily to
 industrial and nonaffiliated pipeline customers.
 
     Gathering and Processing.  The Corporation's operations for the
 processing of natural gas for the recovery of natural gas liquids ("NGL")
 are conducted by EPC.
 
     EPC uses cryogenic and mechanical refrigeration processes at its NGL
 extraction facilities.  The mixed NGL stream, containing the heavier
 hydrocarbons ethane, propane, butane and natural gasoline, is pumped via
 pipeline to Mt. Belvieu, Texas.  The remaining natural gas, primarily
 methane, leaves the NGL plants in gas transmission lines for transportation
 to end-use customers.  See "Properties."
 
     About 60% of NGL product sales are under term contracts of one to
 three years, with prices established monthly.  NGL prices are influenced by
 a number of factors, including supply, demand, inventory levels, the
 product composition of each barrel and the price of crude oil. 
 Profitability is highly dependent on the relationship of NGL product prices
 to the cost of natural gas lost in the extraction process, which is
 commonly termed "shrinkage."
 
     To reduce the impact of shrinkage, EPC strives to replace
 "keep-whole" gas processing contracts with "net-proceeds" contracts. 
 Keep-whole contracts are relatively more profitable during periods of high
 NGL prices and low gas costs because they provide the processor with
 ownership of the entire gas stream.  However, as prices decline, these
 contracts become relatively less profitable because the processor must
 absorb all the shrinkage costs.  Under net-proceeds contracts, the producer
 provides shrinkage volumes, while the processor contributes plant
 facilities and operational costs.  Revenues from NGL sales are apportioned
 between the parties, and the processor is no longer impacted by natural-gas
 feedstock costs.
 
     Gas Marketing.  On June 29, 1995, ENSERCH purchased the principal
 operating assets of Sunrise Energy Services, Inc. and subsidiaries 
 ("Sunrise"), a nonregulated marketer of natural gas.  Effective June 30,
 1995, ENSERCH exchanged shares of its common stock for all the common stock
 of DGS Holdings Corp. ("DGS") in a pooling-of-interests transaction.  DGS,
 through its subsidiary, is a marketer of natural gas and natural-gas
 services.  Enserch Gas Company, ENSERCH's prior marketing company, DGS and
 Sunrise were combined to form EES in 1995.
 
     EES is a marketer of natural gas and natural-gas services to both the
 U.S. wholesale and retail markets, primarily in the Northeast, Midwest and
 West Coast.  EES's marketing activities typically consist of
 (i) contracting to purchase specific volumes of gas from producers,
 pipelines and other suppliers at various points of receipt to be supplied
 over a specific period of time, (ii) aggregating gas supplies and arranging
 for the transportation of these gas supplies and (iii) negotiating to sell
 specific volumes of gas over a specified period of time to local
 distribution companies and other end users.
 
     The marketing activities of EES involve price commitments into the
 future and, therefore, give rise to market risk, which represents the
 potential loss that can be caused by a change in the market value of a
 particular commitment.  To manage these market risks, EES enters into a
 variety of transactions, including forward contracts principally involving
 physical delivery of natural gas and derivative financial instruments,
 including swaps, options, futures and other contractual arrangements.   
 See "Financial Review - Natural Gas Pipeline & GPM" and Note 6 of the Notes
 to Consolidated Financial Statements included in Appendix A for additional
 information on these activities.
 
     Competition.  LSP is the sole transporter of natural gas to LSG's
 distribution systems.  LSP competes with other pipelines in Texas to
 transport natural gas to off-system markets.  This business is highly
 competitive and greatly influenced by the demand to move natural gas across
 Texas to supply Northeast and upper Midwest U.S. markets.  See "Natural Gas
 Distribution - Competition."
 
     NGL processing is highly competitive and includes competition among
 producers, third-party owners and processors for cost-sharing and interest-
 sharing arrangements.
 
     EES pursues markets connected to pipelines other than LSP's.  As
 natural-gas markets continue to evolve following the implementation of the
 1992 Order 636 of the Federal Energy Regulatory Commission ("FERC"),
 additional opportunities are created in the broader, more active trading
 markets and in serving off-system customers.  This highly competitive
 market demands that a wide array of services be offered, including term
 contracts with interruptible and firm deliveries, risk management,
 aggregation of supply, nominations, scheduling of deliveries and storage. 
 ENSERCH significantly increased its presence in these off-system markets
 and its ability to provide these services through the Sunrise and DGS
 transactions.
 
     Regulation.  LSP is wholly intrastate in character and performs
 transportation services in the state of Texas subject to regulation by the
 RRC.  LSP owns no certificated interstate transmission facilities subject
 to the jurisdiction of FERC under the Natural Gas Act, has no sales for
 resale under the rate jurisdiction of FERC and does not perform any
 transportation service that is subject to FERC jurisdiction under the
 Natural Gas Act.
 
     LSP has been an open access transporter under Section 311 of the
 Natural Gas Policy Act of 1978 ("NGPA") on its intrastate transmission
 facilities since July 1988.  Such transportation is performed pursuant to
 Section 311(a)(2) of the NGPA and is subject to an exemption from the
 jurisdiction of the FERC under the Natural Gas Act, pursuant to Section 601
 of the NGPA.
 
     The RRC regulates LSP's transportation charge to LSG for the
 transportation of gas to LSG's distribution systems for sale to residential
 and commercial customers.  LSP's transportation services to other customers
 are provided under standard or competitively negotiated contracts.
 
 NATURAL GAS DISTRIBUTION
 
     LSG owns and operates natural-gas distribution systems and related
 properties.  Through these facilities, it purchases, distributes and sells
 natural gas to over 1.3 million residential, commercial, industrial and
 electric-generation customers in approximately 550 cities and towns,
 including the ll-county Dallas/Fort Worth Metroplex.  LSG also transports
 natural gas within its distribution system as market opportunities require. 
 Operating data for this segment are set forth under "Natural Gas
 Distribution Operating Data" included in Appendix A to this report.
 
     For the year ended December 31, 1995, sales to residential and
 commercial customers accounted for 88% of LSG's total gas sales revenues
 and 84% of natural-gas volumes sold.  Sales to industrial and
 electric-generation customers accounted for the remainder.
 
     LSG's gas sales revenues are influenced by seasonal temperature
 variations.  The majority of LSG's residential and commercial gas customers
 use gas for heating and their needs are directly affected by the mildness
 or severity of the heating season although some 60% of LSG's residential
 and commercial volumes are subject to weather normalization adjustments. 
 Sales to electric-generation customers are affected by the mildness or
 severity of both cooling and heating seasons.
 
     Competition.  Customer sensitivity to energy prices and the
 availability of competitively priced gas in the nonregulated markets
 continue to provide intense competition in the electric-generation and
 industrial-user markets.  Natural gas faces varying degrees of competition
 from electricity, coal, natural gas liquids, oil and other refined products
 throughout LSG's service territory.  Pipeline systems of other companies,
 both intrastate and interstate, extend into or through the areas in which
 LSG's markets are located, creating competition from other sellers of
 natural gas.  Competitive pressure from other pipelines and alternative
 fuels has caused a decline in sales by LSG to industrial and electric-
 generation customers.  Sales by the Corporation's nonregulated companies,
 along with transportation services provided by LSP, have served to offset
 much of the effects of this decline.  As developments in the energy
 industry point to a continuation of these competitive pressures, LSG
 maintains its focus on customer service and the creation of new services
 for its customers in order to remain its customers' supplier of choice.
 
     Source and Availability of Raw Materials.  LSG's gas supply consists
 of contracts for the purchase of dedicated specific reserves, contracts
 with other pipeline companies in the form of service agreements that are
 not related to specific reserves or fields, and gas in storage.  The total
 gas supply as of January 1, 1996, was 754 Bcf, which is approximately 5
 times LSG's purchases during 1995.  Of this total, 197 Bcf are dedicated
 reserves and 32 Bcf are working gas in storage.  Management has calculated
 that 525 Bcf, including 197 Bcf under one agreement, are committed to LSG
 under service agreements.  The January 1, 1996, total gas supply estimate
 is 251 Bcf lower than the January 1, 1995, estimate.  The difference
 resulted from 156 Bcf purchased from existing gas supply, a net downward
 revision of 128 Bcf with respect to estimates for existing sources and
 service agreements, partially offset by new supply additions of 33 Bcf. 
 The net downward revision of existing sources and service agreements of 128
 Bcf is comprised of 78 Bcf from the termination of a major gas-purchase
 contract, 41 Bcf downward adjustment of service and peaking agreement
 availability and 9 Bcf from downward revisions and terminations of various
 other sources.  New supply additions of 33 Bcf consisted of 8 Bcf of new
 dedicated reserves under old contracts and 25 Bcf of availability added
 under new service agreements and peaking contracts.
 
     In 1995, about 86% of LSG's gas requirement was purchased from some
 264 independent producers and nonaffiliated pipeline companies, one of
 which supplied approximately 12% of total requirements.  The remaining 14%
 of LSG's requirement was supplied by affiliates.
 
     LSG estimates its peak-day availability from long-term contracts and
 withdrawals from underground storage to be 1.6 Bcf.  Short-term peaking
 contracts raise this level to meet anticipated sales needs.
 
     During 1995, the average daily demand of LSG's residential and
 commercial customers was .3 Bcf.  The estimated peak-day demand of such
 customers (based upon an arithmetic-mean outside temperature of 15 degrees
 F.) was 2.0 Bcf.  LSG's greatest daily demand in 1995 was on January 4,
 when the arithmetic-mean temperature was 30 degrees F. and  deliveries to
 all customers reached 1.7 Bcf, including estimated deliveries to
 residential and commercial customers of 1.3 Bcf.
 
     To meet peak-day gas demands during winter months, LSG utilizes the
 service of seven affiliated gas storage fields, all of which are located in
 Texas.  These fields have a working gas capacity of 47 Bcf and a day-one
 storage withdrawal capacity of 1.3 Bcf per day.
 
     LSG has historically maintained a contractual right to curtail, which
 is designed to achieve the highest load factor possible in the use of its
 pipeline system while assuring continuous and uninterrupted service to its
 residential and commercial customers.  Under the program, industrial
 customers select their own rates and relative priorities of service. 
 Interruptible service contracts include the right to curtail gas deliveries
 up to 100% according to a strict priority plan.  The last curtailment
 occurred in 1990 and lasted for only 30 hours.
 
     Estimates of gas supplies and reserves are not necessarily indicative
 of LSG's ability to meet current or anticipated market demands or immediate
 delivery requirements because of factors such as the physical limitations
 of gathering and transmission systems, the duration and severity of cold
 weather, the availability of gas reserves from its suppliers, the ability
 to purchase additional supplies on a short-term basis and actions by
 federal and state regulatory authorities.  LSG's curtailment rights provide
 flexibility to meet the human-needs requirements of its customers on a firm
 basis.  Priority allocations and price limitations imposed by federal and
 state regulatory agencies, as well as other factors beyond the control of
 LSG, may affect its ability to meet the demands of its customers.
 
     The LSG supply program is designed to contract for new supplies of
 gas (and to recontract targeted expiring sources) connected to LSP's
 pipeline system.  In addition to being heavily concentrated in the
 established gas-producing areas of central, northern and eastern Texas,
 LSP's intrastate pipeline system also extends into or near the major
 producing areas of the Texas Gulf Coast and the Delaware and Val Verde
 Basins of West Texas.  Nine basins located in Texas are estimated to
 contain a substantial portion of the nation's remaining onshore natural-gas
 reserves.  LSP's pipeline system provides access to all of these basins. 
 LSP is well situated to receive large volumes into its system at the major
 "hubs", such as Katy and Waha, as well as at the major third-party owned
 storage facilities where suppliers maintain instantaneous high delivery
 capabilities.
 
     LSG buys gas under long-term, intrastate contracts in order to assure
 reliable supply to its customers.  Many of these contracts require minimum
 purchases of gas.  In the past, LSG had been unable to take delivery of all
 minimum gas volumes tendered by suppliers under these contracts.  Based on
 estimated gas demand, which assumes normal weather conditions, requisite
 gas purchases are expected to substantially satisfy purchase obligations
 for the year 1996 and thereafter.  See Note 7 of the Notes to Consolidated
 Financial Statements included in Appendix A to this report.
 
     Regulation.  LSG is wholly intrastate in character and performs its
 distribution utility operations in the state of Texas subject to regulation
 by the RRC and municipalities in Texas.  The RRC regulates the charge for
 the transportation of gas by LSP to LSG's distribution systems for sale to
 LSG's residential and commercial consumers.  The RRC has original
 jurisdiction over rates charged to customers for gas delivered outside
 incorporated cities and towns (environs rates).  Rates within incorporated
 cities and towns in Texas are subject to the original jurisdiction of the
 local city council with appellate review by the RRC.
 
     LSG employs a continuing program of rate review for all classes of
 customers in its regulatory jurisdictions.  Rate relief amounting to about
 $14 million in annualized revenue increases, exclusive of changes in gas
 cost, was achieved in Texas with the completion of the 1995 rate program. 
 This amount includes $5 million granted by the four cities in the Dallas
 Distribution System in January 1996.  A smaller rate program is being
 undertaken in 1996 to obtain revenue increases where deficiencies exist. 
 Weather normalization adjustment clauses have been approved by 156 of the
 550 cities served by LSG, representing over 60% of LSG's residential and
 commercial sales volumes.  These clauses allow rates to be adjusted to
 reflect the impact of warmer or colder-than-normal weather during the
 winter months, minimizing the impact of variations in weather on LSG's
 earnings.
 
     LSG's sales to industrial customers are provided under rates
 reflected in standard rate schedules and contracts.  Transportation
 services to industrial and electric-generation customers are provided under
 competitively negotiated contracts.  Regulatory authorities in Texas have
 jurisdiction to revise, review and regulate rates to industrial and
 electric-generation customers but, historically, have not actively
 exercised this jurisdiction because of the existing competitive market. 
 Sales contracts with these customers permit automatic adjustment on a
 monthly basis for the full amount of increases or decreases in the cost of
 gas.
 
     ENSERCH operates in the compressed natural-gas market through the
 Alternative Fuels Division of Lone Star Energy Company ("LSEC") and  two
 natural-gas vehicle affiliates, Fleet Star of Texas, L.C. ("Fleet Star")
 and TRANSTAR Technologies, L.C. ("TRANSTAR") that are both 50% owned by
 LSEC. Through December 31, 1995, the operations of the Alternative Fuels
 Division and affiliates were aligned under the Corporation's natural gas
 pipeline & GPM segment for financial reporting purposes.  Effective
 January 1, 1996, these operations were realigned under the natural gas
 distribution segment.  Fleet Star and FinaStar, a partnership between Fleet
 Star and Fina Oil and Chemical, had 14 public natural-gas fuel stations in
 commercial operation at December 31, 1995.  TRANSTAR provides turnkey
 natural-gas vehicle conversions and other related services and performed
 over 1,200 vehicular natural-gas conversions in 1995, compared with 500
 conversions in 1994.
 
     In South America, LSG is providing its distribution expertise to
 develop a new infrastructure in support of gas systems being constructed to
 service Santiago, Chile, and surrounding communities.  Additionally, newly
 passed legislation in Mexico has opened the door to partial ownership of
 gas pipeline transmission systems by foreign companies. Based upon its
 geographic proximity to the existing U.S.-based, natural-gas reserves, the
 Corporation's affiliates are examining the economic potential to be gained
 by participating in the developing natural-gas infrastructure in Mexico.  
 
 POWER
 
     Enserch Development Corporation ("EDC") develops business
 opportunities primarily in the areas of independent power, including
 cogeneration.  EDC evaluates the risk and rewards of these potential
 ventures; selects for development those ventures with the highest potential
 of success; implements and controls development of each venture; and brings
 together all the resources required to develop, finance, construct, operate
 and manage the selected ventures.  EDC's efforts are currently focused on
 international projects, with decreased emphasis on projects in the United
 States.
 
     EDC has completed the development of three cogeneration plants,
 including a 255-megawatt ("MW") plant in Sweetwater, Texas, that began
 operation in 1989, a 62-MW natural gas-fired cogeneration facility in
 Buffalo, New York, that was completed in 1992 and a 160-MW plant in
 Bellingham, Washington, that began commercial operation in 1993.  The
 electricity produced at the Sweetwater plant is purchased by Texas
 Utilities Electric Company, and thermal energy is sold to United Gypsum
 Company under a long-term agreement.  A subsidiary of EDC is the managing
 general partner of the plant, EEX and EES provide gas to the plant, and LSP
 transports the gas.  The Buffalo plant supplies electricity to Niagara
 Mohawk Company and thermal energy to Outokumpu American Brass, Inc.  The
 electricity produced at the Bellingham plant is sold under a long-term
 power sales agreement with Puget Sound Power & Light, and thermal energy in
 the form of steam and hot water is sold to Georgia-Pacific Corporation. 
 LSEC operates and maintains all three plants and has fixed-cost operating
 and maintenance agreements for providing labor and certain routine
 consumables at each plant, with each of the agreements containing
 escalation provisions.  The agreements for the Buffalo and Bellingham
 plants also contain bonus or penalty provisions based upon plant
 availability.
 
     At the end of 1995, EDC had two international projects in the
 construction and drilling phase.  Construction of a 36-MW coal-fired
 cogeneration facility in the Zhejiang Province of the People's Republic of
 China, in which EDC has a 70% interest, began in the fourth quarter of
 1995.  The plant is expected to be completed in 1998.  Electricity will be
 sold to the Shaoxing Administration of Power Utilization, and steam will be
 sold to several industrial users in the area.  The second project, in which
 EDC will have a 15% interest, is a 300 to 400-MW geothermal power plant in
 Java, Indonesia.  Drilling for  geothermal resource will continue
 throughout 1996, and construction of the power-generation facility is
 scheduled to begin in 1997.  Electricity from the plant will be sold to the
 Indonesian electric utility, PT PLN (PERSERO).
 
     In addition to operating and maintaining cogeneration plants
 developed by EDC, LSEC owns and/or operates four central thermal energy
 plants providing heating and cooling to various institutional customers in
 Texas under agreements which expire in 1996 and 1997.  LSEC is actively
 pursuing new contracts to operate the plants after the existing agreements
 expire.  The expiration of the existing agreements will have a significant
 impact on the Corporation.
 
 CLEAN AIR ACT
 
     The impact of the 1990 amendments to the Clean Air Act ("CAA") on the
 Corporation, its divisions, subsidiaries and affiliates, cannot be fully
 ascertained until all the regulations that implement the provisions of the
 Act have been promulgated.  It is expected that a number of facilities or
 emission sources will require a federally enforceable operating permit, and
 certain emission sources may also be required to reduce emissions or to
 install monitoring equipment under proposed rules and regulations. 
 Management currently believes, however, that if the rules and regulations
 implementing the CAA are adopted as proposed, the cost of obtaining
 permits, operating costs that will be incurred under the operating permit,
 new permit fee structures, capital expenditures associated with equipment
 modifications to reduce emissions, or any expenditures on monitoring
 equipment, in the aggregate, will not have a material adverse effect on the
 Corporation's results of operations.
 
     The CAA has created new marketing opportunities for the sale of
 natural gas that may have a positive effect on the Corporation's results of
 operations.  Natural gas has long been recognized as a clean and efficient
 fuel.  Title II (Mobile Sources) requires lower emissions from light-duty
 vehicles and urban buses that should make alternative fuels such as natural
 gas more attractive and competitive.  In addition, Clean Fuel Fleet
 programs under the CAA will require a certain percentage of fleet vehicles
 to utilize clean-burning alternative fuels such as natural gas in the near
 future.  Further, because chloroflurocarbon compounds ("CFC's"), commonly
 used as refrigerants in large air-conditioning systems must be phased out
 of production by the year 2000, interest has increased in the use of
 natural gas-powered absorption cooling systems that do not use CFC's.  In
 those areas that do not meet the CAA's National Ambient Air Quality
 Standards for ozone, natural gas may play an important role in reducing
 ozone formation and may be substituted for other fuels.  Since Title IV
 (Acid Rain) requires major reductions in sulphur dioxide emissions,
 principally from coal-fired electric power plants, natural gas is expected
 to be considered as a cost-effective alternative for achieving reduced
 sulphur dioxide emissions.
 
 PATENTS AND LICENSES
 
     The Corporation, its divisions and subsidiary companies have no
 material patents, licenses, franchises (excluding gas-distribution
 franchises) or concessions.
 
 EMPLOYEES
 
     At December 31, 1995, the Corporation, its divisions and
 subsidiaries, had approximately 4,167 employees.
 
 EXECUTIVE OFFICERS OF REGISTRANT
 
 <TABLE> 
 <CAPTION>
 
     Name           Age       Office and Business Experience
 <S>                <C>  <C>
 
 D. W. Biegler      49   Chairman and President, Chief Executive           
                         Officer since May 1993 and a Director of the
                         Corporation since September 1991; President
                         and Chief Operating Officer of the
                         Corporation from September 1991 to May 1993.
                         He also served LSG as President from July
                         1985 and as Chairman from January 1989.
 
 G. R. Bryan        51   Vice Chairman, President and Chief Operating
                         Officer of EES since November 1995; Chairman
                         of EDC since February 1993.  He also served
                         LSG as Senior Vice President, Transmission,
                         from February 1987 to February 1993.
 
 M. T. Hunter       46   President and Chief Operating Officer of LSP
                         since June 1995.  Previously he served as
                         President and Chief Operating Officer of
                         Mississippi River Transmission Corporation, a
                         subsidiary of Noram Energy Corp.
  
 D. R. Long         48   Senior Vice President, Administration, since
                         May 1995.  He previously served LSG as Vice
                         President, Human Resources and Services, from
                         January 1995 to May 1995, and as Vice
                         President, Human Resources and Facility
                         Development, from June 1990 to January 1995.
 
 M. E. Rescoe       43   Senior Vice President, Finance, and Chief
                         Financial Officer since September 1995. 
                         Previously he served as Senior Managing
                         Director of Bear, Stearns & Co. from 1992 to
                         July 1995 and was a Senior Vice President,
                         Finance, of Kidder, Peabody & Co. from 1983
                         to 1992.
 
 W. T. Satterwhite  62   Senior Vice President and General Counsel,
                         Chief Legal Officer of the Corporation since
                         May 1972.
 
 R. B. Williams     63   President of LSG since May 1995.  He served
                         as Vice President, Administration, of the
                         Corporation from May 1989 to May 1995.
 </TABLE>
 
     There are no family relationships between any of the above officers. 
 All officers of the Corporation, its divisions and subsidiaries, are
 elected annually by their respective Board of Directors.  Officers may be
 removed by their respective Board of Directors whenever, in the judgment of
 the Board, the best interest of the Corporation, its divisions or
 subsidiaries, as the case may be, will be served thereby.
 
 ITEM 2.  Properties
 
       EEX.  EEX's domestic activities are focused in four regions: the
 Gulf of Mexico; East Texas; North Central Texas; and the Gulf Coast Region
 of Texas, Louisiana, Mississippi and Alabama.  The following table sets
 forth estimated net proved reserves of EEX by region, as estimated by D&M,
 at January 1, 1996:
 
 <TABLE>
 <CAPTION>
                                             Oil                  
                               Natural     and Gas            
                                 Gas       Liquids         Total
   Region                       (Bcf)      (MMBbls)        (Bcfe)  
   ------                      -------     --------        ------  
 <S>                           <C>           <C>          <C>       
 Gulf of Mexico                  127.6       36.4           346.0    
 East Texas                      846.6        7.7           892.8    
 North Central Texas and other   248.9       18.1           357.5    
 Gulf Coast                      139.7        4.3           165.5     
                               -------       ----         -------
   Total Domestic              1,362.8       66.5         1,761.8    
 International                                5.0            30.0     
                               -------       ----         -------
   Total                       1,362.8       71.5         1,791.8   
                               =======       ====         =======
 </TABLE>
 
     See Note 11 of the Notes to Consolidated Financial Statements
 included in Appendix A to this report for additional information on gas and
 oil reserves.
 
     During 1995, EEX filed Form EIA-23 with the Department of Energy
 reflecting reserve estimates for the year 1994.  Such reserve estimates
 were not materially different from the 1994 reserve estimates reported in
 Note 11 of the Notes to Consolidated Financial Statements included in
 Appendix A to this report.
 
     Developed and undeveloped lease acreage as of December 31, 1995, are
 set forth below:
 
 <TABLE>
 <CAPTION>
                      Developed Acres      Undeveloped Acres
                    -------------------  ---------------------
                     Gross      Net(1)    Gross       Net(1)
                    -------    -------   ---------   ---------
 <S>                <C>       <C>        <C>        <C>
 Domestic
  Offshore          141,842    40,329      755,240    416,272
  Onshore           535,294   337,790    1,541,826    901,017
                    -------   -------    ---------  ---------
     Total          677,136   378,119    2,297,066  1,317,289
 International                           2,489,567    618,637
                    -------   -------    ---------  ---------
     Total          677,136   378,119    4,786,633  1,935,926
                    =======   =======    =========  =========
 
 <FN>
 (1) Represents the proportionate interest of EEX in the gross acres under
     lease.
 </FN>
 </TABLE>
 
    EEX purchased about 329,000 net acres of leasehold interests in 1995,
 184,000 of which were in the Gulf of Mexico.  EEX's Gulf of Mexico holdings
 totaled some 457,000 net acres, with an average working interest of 49% in
 212 blocks and an overriding royalty interest in 13 other blocks.  EEX
 operates 103 offshore blocks.  EEX also canceled or allowed to expire 15
 Gulf of Mexico leases during the year, which had been condemned following
 drilling on or near them or after geophysical and geological findings. 
 
    EEX plans further drilling on undeveloped acreage but at this time
 cannot specify the extent of the drilling or predict how successful it will
 be in establishing commercial reserves sufficient to justify retention of
 the acreage.  The primary terms under which the undeveloped acreage can be
 retained by the payment of delay rentals without the establishment of gas
 and oil reserves expire as follows:
 
 <TABLE>
 <CAPTION>
                            Undeveloped Acres Expiring
                   -------------------------------------------
                         Domestic             International
                   -------------------     -------------------
                     Gross       Net         Gross       Net
                   ---------   -------     --------    -------
    <S>            <C>         <C>        <C>          <C>
    1996             663,852   380,697      273,841     68,460
    1997             424,957   243,698      456,401    114,100
    1998 and later 1,208,257   692,894    1,759,325    436,077
 </TABLE>
 
    Drilling rights with regard to a portion of the undeveloped acreage
 may be allowed to expire before the expiration of primary terms specified
 in this schedule by nonpayment of delay rentals.
 
    At December 31, 1995, EEX owned interests in 2,125 gas wells (1,384.2
 net) and 2,345 oil wells (488 net) in the United States and 4 oil wells (1
 net) in Indonesia.  Of these, 226 gas wells (166.4 net) and 43 oil wells
 (34.9 net) were dual completions in single boreholes.
 
    Drilling activity during the three years ended December 31, 1995,
 including the activities of DALEN for all periods shown, is set forth
 below:
 
 <TABLE>
 <CAPTION>
                      1995           1994           1993 
                  -----------    -----------    -----------
                  Gross Net      Gross Net      Gross Net
                  ----- ----     ----- ----     ----- ----
 <S>               <C>  <C>       <C>  <C>       <C>  <C>
 Exploratory Wells:
   Productive      38   24.6      21   13.8       7    3.8
   Dry             47   26.8      56   30.5      33   15.6
                   --   ----      --   ----      --   ----
      Total        85   51.4      77   44.3      40   19.4
                   ==   ====      ==   ====      ==   ====
 
 Development Wells:
   Productive      41   26.4      90   63.0     131   86.6
   Dry              6    3.5      15    7.5       9    4.5
                   --   ----     ---   ----     ---   ----
      Total        47   29.9     105   70.5     140   91.1
                   ==   ====     ===   ====     ===   ====
 <FN>
 Note:    Productive wells are either producing wells or wells capable of
           commercial production, although currently shut-in.  The term "gross"
           refers to the wells in which a working interest is owned, and the
           term "net" refers to gross wells multiplied by the percentage of
           EEX's working interest owned therein.
 </FN>
 </TABLE>
 
     At December 31, 1995, EEX was participating in 69 wells (41 net),
 which were either being drilled or in some stage of completion. 
 
     The number of wells drilled is not a significant measure or indicator
 of the relative success or value of a drilling program because the
 significance of the reserves and economic potential may vary widely for
 each project.  It is also important to recognize that reported completions
 may not necessarily correspond to capital expenditures, since Securities
 and Exchange Commission guidelines do not allow a well to be reported as
 complete until it is ready for production.  In the case of offshore wells,
 this may be several years following initial drilling because of the timing
 of construction of platforms, pipelines and other necessary facilities.
 
     Additional information relating to the gas and oil activities of EEX
 is set forth in Note 11 of the Notes to Consolidated Financial Statements
 included in Appendix A to this report.
 
     LSP.  At December 31, 1995, LSP operated approximately 9,000 miles of
 transmission and gathering lines and operated 34 compressor stations having
 a total rated horsepower of approximately 101,000.  LSP also owns seven
 active gas-storage fields, all located on its system in Texas, and three
 major gas-treatment plants to remove undesirable components from the gas
 stream.
 
     EPC.  EPC has interests in 18 processing plants, 12 of which are
 wholly owned.  
 
     LSG.  At December 31, 1995, LSG operated approximately 23,000 miles
 of distribution mains.  See "Business - Natural Gas Distribution - Source
 and Availability of Raw Materials" for information concerning gas supply of
 Lone Star Gas Company.
 
     LSEC.  LSEC owns three central plants providing heating and cooling
 to institutional customers in Dallas, El Paso and Galveston, Texas.
 
      The Corporation owns a five-building office complex in Dallas,
 containing approximately 453,000 square feet of space that the Corporation,
 LSG, LSP and certain subsidiaries fully occupy.  In addition, the
 Corporation leases a 21-story, 400,000 square-foot building in Houston
 under a two-year lease that is automatically extended each year unless
 terminated.  EEX leases approximately 205,000 square feet of office space
 for its offices in Dallas, Texas, under leases expiring in December 1998
 and August 2002.
 
     See "Financial Review - Liquidity and Financial Resources" included
 in Appendix A to this report for a discussion of the Corporation's 1996 
 capital spending budget by business segment.
 
 ITEM 3.  Legal Proceedings
 
     The Corporation is a party to lawsuits arising in the ordinary course
 of its business.  The Corporation believes, based on its current knowledge
 and the advice of counsel, that all lawsuits and claims would not have a
 material adverse effect on its financial condition.  Additional information
 required hereunder is set forth in Note 7 of the Notes to Consolidated
 Financial Statements included in Appendix A to this report.
 
 ITEM 4.  Submission of Matters to a Vote of Security Holders
 
     Not applicable.
 
 
                            PART II
 
 ITEM 5.  Market for Registrant's Common Equity and Related Stockholder
        Matters
 
     The information required hereunder is set forth under "Common Stock
 Market Prices and Dividend Information" included in Appendix A to this
 report.
 
 ITEM 6.  Selected Financial Data
 
     The information required hereunder is set forth under "Selected
 Financial Data" included in Appendix A to this report.
 
 ITEM 7.  Management's Discussion and Analysis of Financial Condition and
        Results of Operations
 
     The information required hereunder is set forth under "Financial
 Review" included in Appendix A to this report.
 
 
 ITEM 8.  Financial Statements and Supplementary Data
 
     The information required hereunder is set forth under "Independent
 Auditors' Report," "Management Report on Responsibility for Financial
 Reporting," "Statements of Consolidated Income," "Statements of
 Consolidated Cash Flows," "Consolidated Balance Sheets," "Statements of
 Consolidated Common Shareholders' Equity," "Notes to Consolidated Financial
 Statements," "Summary of Business Segments" and "Quarterly Results"
 included in Appendix A to this report.
 
 ITEM 9.  Changes in and Disagreements with Accountants on Accounting and
        Financial Disclosure
 
     None.
 
                            PART III
 
 ITEMS 10-13.
 
     Pursuant to Instruction G(3) to Form 10-K, the information required
 in Items 10-13 (except for information set forth at the end of Part I under
 "Business - Executive Officers of Registrant") is incorporated by reference
 from the Corporation's definitive proxy statement which is being filed
 pursuant to Regulation 14A on or about March 29, 1996.
 
                            PART IV
 
 ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
 
 (a)-1 Financial Statements
 
 The following items appear in the Financial Information section included in
 Appendix A to this report:
 
 <TABLE>
 <CAPTION>
               Item                                        Page
     <S>                                                  <C>  
 
     Selected Financial Data . . . . . . . . . . . . . . . A-2 
     Financial Review. . . . . . . . . . . . . . . . . . . A-4 
     Natural Gas and Oil Exploration and 
        Production Operating Data. . . . . . . . . . . . .A-13 
     Natural Gas Pipeline & Gathering, Processing and
        Marketing Operating Data . . . . . . . . . . . . .A-14 
     Natural Gas Distribution Operating Data . . . . . . .A-15 
     Independent Auditors' Report. . . . . . . . . . . . .A-16 
     Management Report on Responsibility for
        Financial Reporting. . . . . . . . . . . . . . . .A-17 
     Financial Statements:
          Statements of Consolidated Income. . . . . . . .A-18 
          Statements of Consolidated Cash Flows. . . . . .A-19 
          Consolidated Balance Sheets. . . . . . . . . . .A-20 
          Statements of Consolidated Common
             Shareholders' Equity. . . . . . . . . . . . .A-21 
     Notes to Consolidated Financial Statements. . . . . .A-22 
     Summary of Business Segments. . . . . . . . . . . . .A-43 
     Quarterly Results . . . . . . . . . . . . . . . . . .A-44 
     Common Stock Market Prices and Dividend Information .A-45 
 
 </TABLE>
 
 (a)-2 Financial Statement Schedules
 
     The consolidated financial statement schedules are omitted because of
 the absence of the conditions under which they are required or because the
 required information is included in the consolidated financial statements
 or notes thereto.
 
 (a)-3 Exhibits.  The following exhibits are filed herewith unless otherwise 
       indicated:
 
 3.1      Restated Articles of Incorporation of the Corporation currently
          in effect.
 
 3.2*     Bylaws of the Corporation, filed as Exhibit 3.2 to the
          Corporation's Form 10-K for the year ended December 31, 1994..
     
 4.1*     Shareholder Rights Plan, filed as an Exhibit to the
          Corporation's Form 8-A dated April 23, 1986.
 
          Executive Compensation Plan and Arrangements
          (Exhibits 10.01 though 10.12):     
 
 10.1*    Management Incentive Program - Unit Plan and Stock Option Plan,
          as amended, and currently in effect, filed as Exhibit 10.1 to
          the Corporation's Form 10-K for the year ended December 31,
          1991.
 
 10.2*    ENSERCH Corporation Deferred Compensation Plan for Directors,
          filed as Exhibit 10.2 to the Corporation's Form 10-K for the
          year ended December 31, 1994.
 
 10.3*    Director's Deferred Compensation Trust Agreement, as amended,
          and currently in effect, filed as Exhibit 10.3 to the
          Corporation's Form 10-K for the year ended December 31, 1991.
 
 10.4*    Forms of trust agreements relating to compensation and
          supplemental retirement income arrangements executed by certain
          executive officers of the Corporation, filed as Exhibit 10.5 to
          the Corporation's Form 10-K for the year ended December 31,
          1991.
 
 10.5*    ENSERCH Corporation 1981 Stock Option Plan, as amended, and
          currently in effect, as filed as Exhibit 10.6 to the
          Corporation's Form 10-K for the year ended December 31, 1991.
 
 10.6     Forms of Change of Control Agreement executed by certain
          executive officers of the Corporation.
 
 10.7     ENSERCH Corporation Performance Incentive Plan - Calendar Year
          1996.
 
 10.8*    ENSERCH Corporation 1991 Stock Incentive Plan, filed as Exhibit
          10.12 to the Corporation's Form 10-K for the Year Ended
          December 31, 1990.
 
 10.9     ENSERCH Corporation Deferred Compensation Plan and Amendment
          No. 1 thereto dated March 28, 1995, and Amendment No. 2 thereto
          dated January 1, 1996.
 
 10.10*   ENSERCH Corporation Deferred Compensation Trust, filed as
          Exhibit 10.10 to the Corporation's Form 10-K for the year ended
          December 31, 1994.
 
 10.11*   ENSERCH Corporation Retirement Income Restoration Plan and
          Amendment No. 1 thereto dated September 30, 1994, filed as
          Exhibit 10.11 to the Corporation's Form 10-K for the year ended
          December 31, 1994.
 
 10.12*   ENSERCH Corporation Retirement Income Restoration Trust, filed
          as Exhibit 10.12 to the Corporation's Form 10-K for the year
          ended December 31, 1994.
 
 21       Subsidiaries of the Corporation.
 
 23.1     Deloitte & Touche LLP consent to incorporation by reference in
          Registration Statements No. 2-59259, No. 2-77572, No. 33-15623,
          No. 33-40589, No. 33-47911, No. 33-52525 and No. 33-61635.
 
 23.2     DeGolyer and MacNaughton consent letter including consent to
          incorporation by reference in Registration Statements
          No. 2-59259, No. 2-77572, No. 33-15623, No. 33-40589, No.
          33-47911, No. 33-52525 and No. 33-61635.
 
 24       Powers of Attorney.
 
 27       Financial Data Schedule.
 
 99*      Proxy Statement dated at or about March 29, 1996 being filed
          with the Securities and Exchange Commission on or about
          March 29, 1996.
 
     Long-term debt is described in Note 3 of the Notes to Consolidated
 Financial Statements included in Appendix A to this report.  The
 Corporation agrees to provide the Commission, upon request, copies of
 instruments defining the rights of holders of such long-term debt, which
 instruments are not filed herewith pursuant to Paragraph (b)(4)(iii)(A) of
 Item 601 of Regulation S-K.
 
 *Incorporated herein by reference and made a part hereof.
 
 (b) Reports on Form 8-K
 
     No reports on Form 8-K were filed during the three months ended
 December 31, 1995.
 
 
<PAGE>
<PAGE>
                           SIGNATURES
 
     Pursuant to the requirements of Section 13 or 15(d) of the Securities
 Exchange Act of 1934, the Registrant has duly caused this report to be
 signed on its behalf by the undersigned, thereunto duly authorized.
 
                                   ENSERCH Corporation
 
 
 
 March   26 , 1996                  By:  /s/ D. W. Biegler
       -----                            --------------------------
                                        D. W. Biegler,
                                        Chairman and President,
                                        Chief Executive Officer
 
     Pursuant to the requirements of the Securities Exchange Act of 1934,
 this report has been signed below by the following persons in the
 capacities and on the date indicated.
 
 <TABLE>
 <CAPTION>
 
     Signature and Title                              Date
     -------------------                              ----
 <S>                                             <C>
 D. W. Biegler, Chairman and President,
 Chief Executive Officer and Director;
 Frederick S. Addy, Director; B. A.
 Bridgewater, Jr., Director; Odie C. Donald,
 Director; Marvin J. Girouard, Director;
 Joseph M. Haggar, Jr., Director; Thomas W.       March   26 , 1996
 Luce, III, Director; W. C. McCord, Director;           ----- 
 Diana S. Natalicio, Director; M. E. Rescoe,
 Senior Vice President, Finance and Chief
 Financial Officer; J. W. Pinkerton, Vice
 President and Controller, Chief Accounting
 Officer
 
 </TABLE>
 
 By: /s/ D. W. Biegler
     -----------------------
     D. W. Biegler
     Individually and As
     Attorney-in-Fact
 
<PAGE>
<PAGE>                                                           APPENDIX A



                  ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
                         INDEX TO FINANCIAL INFORMATION
                                DECEMBER 31, 1995




                                                                   Page
                                                                   ----

Selected Financial Data...............................              A-2

Financial Review......................................              A-4

Independent Auditors' Report..........................              A-16

Management Report on Responsibility for
  Financial Reporting.................................              A-17

Financial Statements:
  Statements of Consolidated Income...................              A-18

  Statements of Consolidated Cash Flows...............              A-19

  Consolidated Balance Sheets.........................              A-20

  Statements of Consolidated Common
    Shareholders' Equity..............................              A-21

  Notes to Consolidated Financial Statements..........              A-22

Summary of Business Segments..........................              A-43

Quarterly Results.....................................              A-44

Common Stock Market Prices and Dividend Information...              A-45




<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                                 SELECTED FINANCIAL DATA-ENSERCH CORPORATION AND SUBSIDIARY COMPANIES

                                                                       As of or for Year Ended December 31
                                                   -------------------------------------------------------------------------
                                                      1995         1994         1993          1992         1991        1990
                                                   -------------------------------------------------------------------------
                                                               (In millions except ratio and per share amounts)
<S>                                                 <C>         <C>          <C>           <C>          <C>          <C>
INCOME STATEMENT DATA (a)
Revenues
  Natural gas and oil exploration
     and production. . . . . . . . . . . . . . .    $  220.9    $   179.1    $   189.8     $   171.5    $   183.6    $  213.9
  Natural gas pipeline & GPM . . . . . . . . . .       996.4      1,235.8        908.0         639.5        590.4       593.6
  Natural gas distribution . . . . . . . . . . .       887.5        874.7        967.9         923.4        913.2       929.9
  Power and other. . . . . . . . . . . . . . . .        39.8         45.5         48.6          45.7         37.3        28.1
  Less intercompany revenues . . . . . . . . . .      (213.4)      (239.6)      (235.4)       (152.4)      (159.8)     (145.0)
                                                    --------    ---------    ---------     ---------    ---------    --------
    Total revenues . . . . . . . . . . . . . . .     1,931.2      2,095.5      1,878.9       1,627.7      1,564.7     1,620.5
Operating Income (Loss)
  Natural gas and oil exploration
     and production. . . . . . . . . . . . . . .       (11.5)        25.6 (b)    (37.3)(c)      (6.2)(b)     10.9        31.9
  Natural gas pipeline & GPM . . . . . . . . . .        59.6         27.0         73.4          67.7         78.7        72.6
  Natural gas distribution . . . . . . . . . . .        54.6         38.3         34.2 (d)      48.4         54.1        53.8
  Power and other. . . . . . . . . . . . . . . .         3.5          5.8          9.8          13.4          6.1         2.5
  General and other. . . . . . . . . . . . . . .        (8.5)        (8.1)       (11.9)        (16.8)       (15.4)      (18.2)
                                                    --------     --------    ---------     ---------    ---------    --------
    Total operating income . . . . . . . . . . .        97.7         88.6         68.2         106.5        134.4       142.6
Other Income (Expense) - Net (e) . . . . . . . .        (1.0)        (6.0)          .1         (12.6)        14.6        49.5
Interest and Other Financing Costs . . . . . . .       (83.3)       (69.3)       (77.7)        (94.5)       (92.9)      (99.0)
Income (Taxes) Benefit . . . . . . . . . . . . .         (.9)        68.7 (f)     (6.6)(f)       2.2        (17.8)      (25.7)
Minority Interest. . . . . . . . . . . . . . . .          .6          (.5)                        .2          (.5)        (.2)
                                                   ---------    ---------    ---------     ---------    ---------    --------
Income (Loss) from Continuing Operations . . . .        13.1         81.5        (16.0)          1.8         37.8        67.2
Income (Loss) from Discontinued Operations . . .                     20.6         75.4         (13.8)       (18.6)       35.5
Extraordinary Loss on Extinguishment of Debt . .                                               (15.3)
                                                    --------    ---------    ---------     ---------    ---------    --------
Net Income (Loss). . . . . . . . . . . . . . . .        13.1        102.1         59.4         (27.3)        19.2       102.7
Earnings (Loss) Applicable to Common Stock . . .         1.4         90.5         46.7         (40.3)         4.9        88.5
Per Share of Common Stock
  Income (loss) from continuing operations after
    provision for preferred dividends. . . . . .         .02         1.03         (.42)         (.16)         .35         .80
  Discontinued operations. . . . . . . . . . . .                      .30         1.11          (.21)        (.28)        .54
  Extraordinary loss . . . . . . . . . . . . . .                                                (.23)
                                                    --------    ---------    ---------     ---------    ---------    --------
  Earnings (Loss) Applicable to Common Stock . .         .02         1.33          .69          (.60)         .07        1.34
Average Common and Dilutive Common
  Equivalent Shares Outstanding. . . . . . . . .        68.3         68.0         67.8          66.9         66.3        66.2

COMMON STOCK DATA
Cash Dividends Declared and Paid (g) . . . . . .    $    .20     $    .20     $    .20      $    .80     $    .80    $    .80
Market Price
  High . . . . . . . . . . . . . . . . . . . . .      18 5/8       19 1/8       22 5/8        16 1/2       21 3/8      28 1/8
  Low. . . . . . . . . . . . . . . . . . . . . .      12 5/8       12 1/8       14 1/8        10 3/8       12 3/4      18 1/2
Common Shareholders' Equity per Share. . . . . .       10.50        10.65         9.54          9.00        10.32       10.97
Shares Outstanding at Year-end (a) . . . . . . .        68.5         68.2         67.9          67.2         66.5        66.0

BALANCE SHEET DATA (a)
Property, Plant and Equipment - Net. . . . . . .    $2,726.8     $2,253.5     $2,119.1      $2,065.9     $2,152.2    $2,118.1
Total Assets . . . . . . . . . . . . . . . . . .     3,381.1      2,888.5      2,806.0       3,158.9      3,169.8     3,271.0
Net Working Capital (Deficiency) . . . . . . . .      (185.5)      (157.1)      (191.8)          2.5        (42.5)       65.6
Current Ratio. . . . . . . . . . . . . . . . . .         .74          .77          .74          1.00          .95        1.08
Unused Lines of Credit . . . . . . . . . . . . .    $  600.0     $  600.0     $  635.0      $  485.0     $  650.0    $  600.0

CAPITAL STRUCTURE (a)
Senior Long-term Debt. . . . . . . . . . . . . .    $  885.2     $  726.3     $  640.0      $  865.3     $  757.6    $  774.3
Convertible Subordinated Debentures. . . . . . .        90.8         90.8         90.8          90.8        205.7       215.7
Mandatorily Redeemable Preferred Securities
  of Subsidiary of EEX . . . . . . . . . . . . .       150.0
Minority Interest in Subsidiaries. . . . . . . .       156.4         12.1          8.8           5.1          5.5         6.1
Preferred Stock. . . . . . . . . . . . . . . . .       175.0        175.0        175.0         175.0        175.0       175.0
Common Shareholders' Equity. . . . . . . . . . .       719.2        726.2        647.6         605.4        686.5       724.0
                                                    --------     --------     --------      --------     --------    --------
  Total Capitalization . . . . . . . . . . . . .     2,176.6      1,730.4      1,562.2       1,741.6      1,830.3     1,895.1
Senior Long-term and Convertible Debt
  Ratio (Percent). . . . . . . . . . . . . . . . .      44.8         47.2         46.8          54.9         52.6        52.2

                                A-2
<PAGE>
<PAGE>

<FN>
(a)   The consolidated financial statements have been restated to include the results of DGS Holdings Corp., following a
      pooling-of-interests transaction in June 1995, in the Natural Gas Pipeline & GPM segment and to reflect the realignment
      of business segments in 1995.
(b)   1994 includes a $7.6 million pretax ($4.9 million after-tax, $.07 per share) gain from the sale of an inactive offshore
      pipeline and facilities.  1992 includes a $16.5 million pretax ($10.9 million after-tax, $.16 per share) write-down of
      the inactive offshore pipeline and facilities.
(c)   Includes a $41.4 million pretax ($26.9 million after-tax, $.40 per share) charge as a result of an adverse judgment in
      litigation and a $13.3 million pretax ($8.6 million after-tax, $.13 per share) write-down of non-U.S. gas and oil
      properties.
(d)   Includes a $12.0 million pretax ($7.8 million after-tax, $.12 per share) charge principally for severance expenses
      associated with re-engineering distribution operations.
(e)   1992 includes a $15.5 million pretax ($10.2 million after-tax, $.15 per share) provision for litigation; 1991 includes
      a $15.1 million pretax ($10.0 million after-tax, $.15 per share) gain from the sale of Oklahoma utility properties and
      non-U. S. gas and oil assets; and 1990 includes a $34 million pretax ($22 million after-tax, $.33 per share) gain from
      the sale of investment in Oceaneering International, Inc.
(f)   1994 includes a $70.0 million ($1.03 per share) reduction of deferred income taxes associated with the reorganization
      of partnerships to form Enserch Exploration, Inc.  1993 includes a $10.8 million ($.16 per share) charge from the 1%
      increase in the statutory federal income-tax rate on corporations.
(g)   In addition, 2 million shares of Pool Energy Services Company common stock were distributed in 1990.  The approximate
      value per share of ENSERCH common stock of this distribution was $.33.
</FN>
</TABLE>

                                A-3
<PAGE>
<PAGE>
                                  ENSERCH CORPORATION
                                    FINANCIAL REVIEW


     On June 8, 1995, ENSERCH's partially owned subsidiary, Enserch
Exploration, Inc. (EEX), acquired for cash all of the capital stock of DALEN
Corporation (DALEN), a gas and oil exploration and production company.  On
June 29, 1995, ENSERCH purchased for cash the principal operating assets of
Sunrise Energy Services, Inc. and subsidiaries (Sunrise), a nonregulated
marketer of natural gas.  Effective June 30, 1995, ENSERCH exchanged shares
of its common stock for all of the common stock of DGS Holdings Corp. (DGS).
DGS, through its subsidiary, is a major marketer of natural gas and natural-
gas services.  The "purchase" method was used to account for the DALEN and
Sunrise acquisitions; therefore, consolidated results include results of
operations for these businesses from the date of acquisition.  The "pooling
of interests" method was used to account for the DGS transaction, and
consolidated results for all periods presented have been restated to include
the results of DGS.

     Earnings applicable to common stock for the year 1995 were $1.4 million
($.02 per share), compared with $90 million ($1.33 per share) for 1994 and
$47 million ($.69 per share) for 1993.

CONTINUING OPERATIONS

     Results from continuing operations, after provision for preferred
dividends, were income of $1.4 million ($.02 per share) in 1995, income of
$70 million ($1.03 per share) in 1994 and a loss of $29 million ($.42 per
share) in 1993.  Income from continuing operations, after provision for
preferred dividends, in 1994 benefited from non-recurring items that together
totaled $75 million ($1.10 per share), while 1993 results included non-
recurring items that reduced income by $54 million ($.80 per share).
Excluding these unusual items from 1994 and 1993 results, 1995 income from
continuing operations of $1.4 million ($.02 per share) compares with a loss
of $5.1 million ($.07 per share) in 1994 and income of $25 million ($.38 per
share) in 1993. The 1994 unusual items included a $70 million reduction of
deferred income taxes associated with the reorganization of partnerships to
form EEX and a $4.9 million after-tax ($7.6 million pretax) gain from the sale
of assets.  Unusual items for 1993 included an $8 million after-tax
($12 million pretax) charge principally for severance expenses associated with
the re-engineering of the natural gas distribution segment, an $11 million
charge from the 1% increase in the statutory federal income-tax rate on
corporations, a $9 million after-tax ($13 million pretax) write-down of non-
U.S. gas and oil properties and a $27 million after-tax ($41 million pretax)
charge as a result of an adverse judgment in litigation.

     Operating income for 1995 was $98 million versus $89 million in 1994 and
$68 million in 1993.  Excluding the effects of the 1994 and 1993 unusual
items, operating income was $81 million for 1994 and $135 million for 1993.
Variations in revenues and operating income for each business segment are
discussed below.

                                A-4
<PAGE>
<PAGE>
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION

     In June 1995, EEX acquired DALEN for cash of $340 million and assumed
DALEN's bank debt of $115 million.  The acquisition of DALEN increased proved
reserves 397 billion cubic feet of natural-gas equivalent (Bcfe) and lowered
the average reserve life of EEX's properties by about 25%.

     In September 1995, EEX sold 20 million shares of its common stock to the
public for net proceeds of $208 million, increasing the public ownership
interest in EEX to 16.6%.  ENSERCH's equity interest in EEX, after the
reduction in ownership percentage, increased $59 million.  In accordance with
the full-cost accounting method, ENSERCH credited the $59 million to the
carrying value of gas and oil properties.

     In the third quarter of 1995, a Mobil Corporation (Mobil) affiliate
acquired a 40% working interest in EEX's Garden Banks Block 388 project,
representing the sale of 81.2 Bcfe of proved reserves.  EEX, which now owns
a 60% working interest in and remains the operator of the project, received
cash, property interests and future work commitments on the project.  In
addition, ENSERCH was relieved of operating lease obligations of approximately
$140 million, as well as 40% of the capital expenditures required to complete
the project.  In October 1995, another affiliate of Mobil purchased a 40%
working interest in EEX's Green Canyon Block 254 project, and an affiliate of
Reading & Bates Corp. purchased a 20% working interest in the project.  These
transactions represented the sale of 206 Bcfe of reserves proved during 1995.
EEX, which now has a 40% working interest in and remains the operator of the
project, received cash, an interest in a gas and oil property and future work
commitments.

     EEX's natural-gas reserves at January 1, 1996, were 1.36 trillion cubic
feet (Tcf), compared with 1.04 Tcf the year earlier, as estimated by DeGolyer
and MacNaughton (D&M), independent petroleum consultants.  The sharply higher
gas reserves are principally attributable to the DALEN acquisition. Oil and
condensate reserves, including natural gas liquids attributable to leasehold
interests, were 71 million barrels (MMBbls), compared with the year-earlier
level of 51 MMBbls.  On a Bcfe basis, over 200% of 1995 production was
replaced by additions and revisions, exclusive of the net gain from the DALEN
acquisition.

     In December 1995, EEX announced plans to offer for sale its Rocky
Mountain area properties, which are in six states and aggregate over
250 thousand net acres.  These properties were mostly acquired as part of the
DALEN acquisition and are being offered for sale because they are not within
the core area of EEX's other properties.  Total reserves for the Rocky
Mountain properties at January 1, 1996, as estimated by D&M, were 223 Bcfe,
of which 169 Bcfe were proved.  Production from these properties in 1995
averaged 40 million cubic feet of natural-gas equivalent per day.  The sale
is expected to be concluded in the second quarter of 1996.  EEX intends to use
the proceeds from the sale to reduce its debt.

                                A-5
<PAGE>
<PAGE>
     Operating income of the natural gas and oil exploration and production
business segment is strongly influenced by fluctuations in product prices and
volumes as shown in the table of Operating Data.  DALEN's operations are
included since acquisition on June 8, 1995 and contributed 1995 operating
income of $6.9 million, with revenues of $70.4 million and operating expenses
of $63.5 million.  DALEN's natural-gas revenues were $49 million on sales
volumes of 31 billion cubic feet (Bcf) at an average sales price of $1.60 per
thousand cubic feet (Mcf).  DALEN's oil and other revenues totaled
$21 million; the average sales price for oil was $16.61 per barrel, and oil
sales volumes were 1.1 MMBbls.

     The following comparisons of period-to-period operating results exclude
the impact of DALEN in 1995 and the previously noted unusual items in 1994 and
1993.  There was an operating loss for 1995 of $18 million, compared with
income of $18 million for 1994 and $17 million for 1993.  Revenues for 1995
were $29 million (16%) lower than in 1994, reflecting a $37 million (25%)
decrease in natural-gas revenues, but an $8 million (23%) improvement in oil
and other revenues.  The average natural-gas sales price per Mcf of $1.82 in
1995, excluding DALEN, declined 15% from the 1994 average of $2.15, causing
a $23 million decline in revenues.  Natural-gas sales volumes of 59 Bcf,
excluding DALEN, were 12% less than in 1994, reducing revenues by $14 million.
The lower volumes primarily resulted from less capital spending to replace gas
production due to low gas prices and the normal decline in production from
several mature fields and Mississippi Canyon Block 441 in the Gulf of Mexico.
The higher oil revenues reflect a 10% improvement in the average sales price
and a 12% increase in sales volumes from the start-up of production from the
Garden Banks project in late September and increased production from
exploration and development activities in Hardeman and Shackelford counties
in North Texas.

     Operating expenses for 1995, excluding DALEN, were $7.8 million (5%)
higher than in 1994, primarily due to direct costs of $7.4 million related to
the Garden Banks project.  As expected, the commencement of sales from this
project in late September detracted from 1995 results, producing an operating
loss of  $3.6 million, as fixed operating costs exceeded revenues from the
initial levels of production.  Some operating costs and amortization vary with
production, but other costs and the equipment lease costs are essentially
fixed and will decline on a per unit basis as production increases.  Operating
results from the Garden Banks project are expected to improve in 1996 as
production begins from several additional development wells and the related
equipment lease and other fixed costs are spread over greater production.
Based on current prices, the Garden Banks project is expected to achieve
breakeven results when production reaches the equivalent of 11 to 12 thousand
gross barrels of oil per day, which is projected to occur by mid-year 1996.
Expenses for 1995 included a $1.8 million provision for injuries and damages
claims, while 1994 expenses benefited from credits of $2.0 million associated
with litigation accruals.  Partially offsetting were lower depreciation and
amortization expense and reduced revenue related taxes resulting from
decreased sales volumes.

                                A-6
<PAGE>
<PAGE>
     The total amortization rate per thousand cubic feet of natural-gas
equivalent was $1.04 in 1995, compared with $1.08 in 1994 and $1.03 in 1993.
The 1995 rate benefited from reserve additions for Green Canyon Block 254 and
DALEN and the previously noted $59 million credit to capitalized costs as a
result of the EEX common stock sale.  The increase in the rate from 1993 to
1994 was caused by higher onshore exploratory expenditures and costs for
equipment under capital leases.

     The slight improvement in operating income from 1993 to 1994 was
attributable to lower operating expenses, primarily resulting from year-to-
year differences in the provision for injuries and damages claims.  Revenues
for 1994 were 6% lower than in 1993 due to decreased sales volumes for both
natural gas and oil and lower oil prices, partially offset by slightly higher
natural-gas prices.  Natural-gas sales volumes decreased 4% due to reduced
production from several high-volume fields in South Texas and offshore
Louisiana.

     EEX manages a portion of the risk associated with fluctuations in the
price of natural gas and oil through the use of hedging techniques such as gas
and oil swaps, collars and futures agreements.  In total, gas and oil price
hedging activities increased 1995 revenues by $.1 million versus $4.3 million
in 1994 but reduced revenues by $3.7 million in 1993.  As a result of a
temporary cessation to the historical correlation of natural-gas prices in the
physical market that serves as the delivery point for NYMEX futures contracts
and the prices in certain other physical markets where EEX sells a substantial
portion of its natural-gas production, a $6.0 million mark-to-market loss was
recognized in the fourth quarter of 1995 on contracts that no longer served
as hedges (see Note 6 of the Notes to Consolidated Financial Statements). At
December 31, 1995, EEX had outstanding swaps, collars and futures agreements
that were entered into as hedges extending through December 31, 1996 to
exchange payments on 39 Bcf of natural gas and 655 thousand barrels of oil.
At December 31, 1995, after giving effect to the $6.0 million mark-to-market
loss mentioned above, there were $1.3 million of net unrealized and
unrecognized hedging losses based on the difference between the strike price
and the NYMEX futures price for the applicable trading month.  In addition,
there were $2.4 million of realized losses on hedging activities which were
deferred and will be applied as a reduction in revenues in the month of
physical sale of production.

     Gas and oil prices are subject to seasonal and other fluctuations.  A
decline in prices from year-end 1995 levels or other factors, without
mitigating circumstances, could cause a future write-down of capitalized costs
and a non-cash charge against income under the full-cost accounting method
cost center ceiling limitation.  At June 30 and September 30, 1995, ENSERCH's
full-cost ceiling amount attributable to properties acquired in the DALEN
acquisition was significantly less than the unamortized cost of producing
properties acquired, but at December 31, 1995, the ceiling amount exceeded
costs by some $19 million.  ENSERCH believes that the DALEN properties have
significant exploration and development potential and that the unamortized
cost of the gas and oil properties acquired is recoverable from future
production.  The Securities and Exchange Commission has granted a waiver of
the full-cost ceiling limitation on these properties through June 30, 1996.

                                A-7
<PAGE>
<PAGE>
NATURAL GAS PIPELINE & GPM

     ENSERCH's pipeline and gas marketing operations, formerly reported with
the natural gas transmission and distribution segment, and the gas processing
operations, formerly reported separately as the natural gas liquids processing
segment, have been combined to form the natural gas pipeline & gathering,
processing and marketing (GPM) business segment.  Distribution utility
operations are reported as the natural gas distribution business segment.
Operating income from the natural gas pipeline & GPM segment was $60 million
in 1995, $27 million in 1994 and $73 million in 1993.  The table of Operating
Data provides revenue and other statistical data for the segment.

     Pipeline operations had 1995 operating income of $49 million versus
$25 million in 1994 and $52 million in 1993.  The improvement in 1995
principally came from a $25 million reduction in the cost of gas lost in
transmission.  While such losses result primarily from various physical
factors, the 1994 losses included significant out-of-period adjustments.
Pipeline revenues for 1995 of $143 million were slightly higher than 1994
revenues and about the same as in 1993.  Pipeline throughput totaled 561 Bcf
in 1995, 542 Bcf in 1994 and 543 Bcf in 1993.  Heating degree days for 1995
were about the same as the year earlier and 10% below normal.  Mild winter
weather adversely impacted results for pipeline operations by an estimated
$5 million in 1995 and some $4 million in 1994.  Winter weather was slightly
colder than normal in 1993. Operating expenses for 1995 were up slightly from
1994, which was up slightly from 1993.

     In June 1995, ENSERCH purchased for cash the principal operating assets
of Sunrise and exchanged 1,204,098 shares of its common stock for all of the
common stock of DGS.  DGS and Sunrise expand ENSERCH's energy services
capabilities and broaden its marketing relationships into new areas on the
West Coast and in the Midwest and Northeast.  ENSERCH's gas marketing
operations are now conducted by Enserch Energy Services, Inc., formerly
Enserch Gas Company, and subsidiaries (EES) and include the acquired
operations of DGS and Sunrise.

     Operating income from natural gas marketing operations for 1995 was
$6.1 million, compared with $.9 million in 1994 and $17 million in 1993.  The
higher income for 1995 was primarily due to an improvement in gas margin
compared with the year earlier, partially offset by an increase in operating
expenses.  The lower income in 1994 was attributable to both a sharp decline
in gas margin due to various market-driven pressures and higher operating
expenses.  Natural gas marketing sales volumes and revenues decreased sharply
from 1994 after growth of about 50% from 1993.  Volumes in 1995 were 14%
lower, primarily due to the decision to de-emphasize some wholesale marketing,
and gas prices were 12% lower and accounted for the remainder of the decline.
As part of its natural gas marketing activities,  EES enters into forward
contracts principally involving physical delivery of natural gas and
derivative financial instruments, including swaps, options, futures and other
contractual arrangements.  These activities involve price commitments into the
future and, therefore, give rise to market risk.  At December 31, 1995,
natural gas marketing operations had net commitments to purchase approximately
32 Bcf of natural gas through the year 2000 with offsetting net financial
positions to sell approximately 26 Bcf, including commitments to purchase

                                A-8
<PAGE>
<PAGE>
approximately 40 Bcf from EEX and financial positions to sell the same
quantity.  There was a net unrealized and unrecognized gain of $2.7 million
at December 31, 1995 on these contracts.  At year-end 1994, a $4 million
charge was recorded to reflect lower year-end prices on forward purchase
contracts.

     Natural gas processing activities contributed operating income of
$4.2 million in 1995, compared with $1.0 million in 1994 and $5.0 million in
1993.  Fluctuations in natural gas liquids (NGL) demand caused by overall
economic conditions, price volatility for NGL products and natural-gas
feedstock costs are the major factors that influence financial results in the
NGL processing business.  Depreciation expense was $3.0 million lower in 1995
as several plants became fully depreciated at the end of 1994.  NGL sales
volumes for 1995 of 6.0 MMBbls were slightly ahead of 1994 and about the same
as in 1993, while the average sales price per barrel of $11.66 was virtually
unchanged from 1994 and was 6% lower than in 1993.

NATURAL GAS DISTRIBUTION

     The table of Operating Data reflects the effects of variable weather
patterns on natural gas distribution operations.  Operating income for 1995
was $55 million, compared with $38 million in 1994 and $46 million in 1993,
excluding the $12 million charge in 1993 primarily for severance expenses
associated with re-engineering.  The higher income in 1995 reflects lower
operating expenses resulting from cost reduction measures initiated in prior
years.  Sales volumes to the high margin residential and commercial customer
category in 1995 were virtually the same as in 1994, which was 10% below 1993.
In 1995, total heating degree days were 90% of normal, compared with 91% in
1994 and 104% in 1993. Mild winter weather adversely impacted results for this
segment by an estimated $5.5 million in 1995 and some $3 million in 1994, but
colder weather had a $1.2 million positive impact in 1993.

     Rate increases granted as a result of the 1995 rate program will, on a
normal weather basis, increase annual revenues by approximately $14 million,
with some $10 million of the revenue improvement to come in 1996.  Over 60%
of Lone Star's volumes sold to residential and commercial customers are now
covered by a weather normalization clause.

POWER

     ENSERCH's power activities had 1995 operating income of $3.5 million,
compared with $5.8 million for 1994 and $9.8 million for 1993.  No projects
were closed in 1995 or 1994.  In 1993, results benefited from a $15 million
gain from the sale of a position in a power project that had been scheduled
for development.

OTHER

     Other income/expense consists principally of gains on disposal of assets
and interest income, less discounts on sales of receivables.  In addition,
1994 included $2.7 million of costs associated with the reorganization of
partnerships to form EEX and a $1.4 million loss on the early redemption of

                                A-9
<PAGE>
<PAGE>
sinking fund debentures, and 1993 included a $5.6 million provision for
interest awarded in the litigation judgment mentioned earlier.

     Interest expense and other financing costs for 1995 were $83 million,
compared with $69 million in 1994 and $70 million in 1993, excluding
$8 million not related to borrowings.  The increase in 1995 was primarily due
to the $455 million of debt issued and assumed in the acquisition of DALEN in
June 1995.  Net proceeds of $208 million received in September 1995 from the
sale of EEX common stock were used to reduce debt.

DISCONTINUED OPERATIONS

     The 1994 income from discontinued operations of $21 million ($.30 per
share) arose from the sale of Enserch Environmental Corporation, partially
offset by a $10 million ($17.5 million pretax) loss provision to recognize
that costs and expenses incurred for the windup of other discontinued
businesses would be greater than previously estimated.  The 1993 results of
$75 million ($1.11 per share) primarily arose from the sale of the principal
operating assets of Ebasco Services Incorporated.  At December 31, 1995,
discontinued businesses had assets of $74 million, consisting principally of
retained claims and accounts receivable, and current and other liabilities and
reserves of $47 million.  The Corporation has filed suit against certain
parties to recover amounts outstanding.  Management expects that substantially
all disputes will be resolved by year-end 1997 and that adequate provision for
uncollectible claims and accounts receivable, income-tax matters and expenses
for windup of discontinued operations has been made.

LIQUIDITY AND FINANCIAL RESOURCES

     Net cash flows from operating activities of continuing operations for
1995 totaled $253 million, compared with $91 million in 1994 and $203 million
in 1993.  The 1994 amount is after a $62 million payment relating to the 1993
final adverse judgment in litigation.  Income before depreciation and
amortization and deferred income taxes was $26 million higher than in 1994.
Recoveries of producer settlements, which provided $51 million in 1995, are
now substantially complete with $10 million remaining to be recovered. Current
operating assets and liabilities and other changes provided $26 million in
1995 versus a requirement of $46 million in 1994, exclusive of the litigation
payment.

     Investing activities required net cash flows of $605 million, compared
with $236 million in 1994 and $206 million in 1993.  The 1995 requirement
includes $333 million for the DALEN acquisition, $9 million for the Sunrise
acquisition and a $7 million investment in a gas distribution business in
Mexico.

     In June 1995, ENSERCH issued $150 million of 7 1/8% Notes due 2005, with
the proceeds used to prepay a variable rate note due in 1998.  Also in June
1995, EEX borrowed $500 million, including $350 million under a four-year
revolving credit agreement, to pay the purchase price of $340 million for the
capital stock of DALEN, repay DALEN's bank debt of $115 million and reduce
advances from ENSERCH by $45 million.  In September 1995, EEX used the
$208 million proceeds from the public sale of 20 million shares of its common

                                A-10
<PAGE>
<PAGE>
stock to reduce the borrowing under the revolving credit agreement.  In August
1995, the proceeds from $150 million of mandatorily redeemable preferred
securities issued by a subsidiary of EEX were used to replace EEX's temporary
borrowings.  The dividends on the preferred securities are included in
interest and other financing costs.

     Discontinued operations required cash of $28 million in 1995, principally
for the repurchase of previously sold receivables.  Discontinued operations
required cash of $.9 million in 1994.  Net proceeds from the 1994 sale of
Enserch Environmental of $98 million included the recovery of $32 million
needed for working capital in 1994 prior to the sale.  Also in 1994, there was
a requirement of $22 million for the remittance of December 1993 collections
of sold receivables, plus requirements for the payment of accrued expenses,
taxes and other retained obligations relating to the 1993 sale of Ebasco.
Cash provided by discontinued operations in 1993 of $318 million included net
proceeds from the sale of the principal operating assets of Ebasco and
$100 million from the limited recourse sale of Ebasco receivables.

     Total capitalization at December 31, 1995 was $2.2 billion, an increase
of $446 million from year-end 1994, principally reflecting $160 million
outstanding under EEX's revolving line of credit, $150 million of mandatorily
redeemable preferred securities issued by a subsidiary of EEX and a
$148 million increase in minority interest in common equity of EEX.  As a
percentage of total capitalization, common shareholders' equity plus minority
interest in subsidiaries decreased from 42.7% at December 31, 1994 to 40.2%
at year-end 1995.  EEX intends to use the proceeds from the sale of its Rocky
Mountain area properties to reduce its debt.  In addition, the Corporation is
obligated under operating lease arrangements for facilities used on the Garden
Banks Block 388 project (see Note 7 of the Notes to Consolidated Financial
Statements).  At December 31, 1995, $416 million of common shareholders'
equity was free of restrictions as to the payment of dividends and redemption
of capital stock.  The current ratio was .74 at the end of 1995, .77 at the
end of 1994 and .74 at the end of 1993.

     ENSERCH has bank lines in the form of a three-year revolving agreement
totaling $600 million, all unused at year-end 1995.  In addition, EEX has a
$350 million four-year revolving credit agreement, $190 million of which was
unused at December 31, 1995.

     Planned property, plant and equipment additions for 1996 total
$296 million, including $187 million for natural gas and oil exploration and
production, $43 million for natural gas pipeline & GPM, $64 million for
natural gas distribution and $2 million for other requirements.  The planned
expenditures are expected to be funded from internal cash flow and external
financings as required.

     Inflation during recent years has had little effect on capital costs and
results of operations.

                                A-11
<PAGE>
<PAGE>
FOURTH-QUARTER RESULTS

     Earnings applicable to common stock for the fourth quarter of 1995 were
$7.8 million ($.11 per share), compared with a loss of $4.6 million ($.07 per
share) for the fourth quarter of 1994, after excluding the $94 million ($1.38
per share) of unusual items.  Excluding unusual items in 1994, operating
income improved $16 million to $30 million.  Operating results for the natural
gas pipeline & GPM and natural gas distribution business segments were both
higher than in the 1994 fourth quarter; however, somewhat lower prices for
natural gas, the $6 million mark-to-market loss recognized on gas price
hedging activities and start-up of production at Garden Banks in the fourth
quarter of 1995 caused results for the natural gas and oil exploration and
production segment to be below the same quarter a year ago.

NEW ACCOUNTING STANDARDS

     Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"
will become effective for the Corporation in 1996.  This statement establishes
accounting standards for the impairment of long-lived assets, certain
identifiable intangibles and goodwill.  The new standard is not expected to
have a significant effect on results of operations or financial position in
the foreseeable future.  ENSERCH's gas and oil properties continue to be
separately evaluated at the end of each accounting period under full-cost
accounting rules.

     Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation" encourages, but does not require, companies to
recognize compensation expense for grants of stock, stock options and other
equity instruments to employees based on new fair value accounting rules.
This new accounting principle is effective for the Corporation's fiscal year
ending December 31, 1996.  Managements intends to adopt the disclosure
alternative of this pronouncement.




                                A-12
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
              NATURAL GAS AND OIL EXPLORATION AND PRODUCTION OPERATING DATA



                                                                  For Year Ended December 31
                                         --------------------------------------------------------------------------------------
                                             1995          1994            1993           1992            1991          1990
                                         --------------------------------------------------------------------------------------
<S>                                        <C>           <C>             <C>            <C>             <C>            <C>
Operating Income (Loss)
  (in millions). . . . . . . . . . . .      $(11.5)       $ 25.6          $(37.3)        $ (6.2)         $ 10.9         $ 31.9

Revenues (in millions) . . . . . . . .      $220.9        $179.1          $189.8         $171.5          $183.6         $213.9

Sales Volumes
  Natural gas (Bcf). . . . . . . . . .        90.2          67.1            70.0           65.2            70.1           76.9
  Oil and condensate (MMBbls). . . . .         3.4           2.0             2.1            2.3             2.8            3.1

Average Sales Price
  Natural gas (per Mcf). . . . . . . .      $ 1.74        $ 2.15          $ 2.09         $ 1.82          $ 1.76         $ 1.85
  Oil and condensate (per Bbl) . . . .       16.86         15.38           17.24          19.20           20.31          22.39

Net Wells
  Drilled. . . . . . . . . . . . . . .          81            74              79             19              67             53
  Productive . . . . . . . . . . . . .          51            44              64              8              52             42

Proved Reserves (at December 31)
  Natural gas (Bcf). . . . . . . . . .     1,362.8       1,041.7         1,086.5        1,101.4         1,168.1        1,236.9
  Oil and condensate (MMBbls). . . . .        71.5          50.6            39.3           39.2            40.0           32.3
    Total Bcfe (a) . . . . . . . . . .     1,791.8       1,345.3         1,322.3        1,336.6         1,408.1        1,430.5

Standardized Measure of Discounted
  Future Net Cash Flows (in millions).      $1,238        $  827          $  831         $  820          $  812         $  963

Data in Equivalent Energy Content
 (per Mcfe) (a)
  Production revenue . . . . . . . . .      $ 1.93        $ 2.21          $ 2.21         $ 2.07          $ 2.08         $ 2.22
  Production and operating costs(b). .         .44           .39             .37            .36             .40            .36
  Depreciation and amortization. . . .        1.04          1.08            1.03           1.01             .93            .82


Operating Income Reconciliation from EEX to ENSERCH Segment

Operating income (loss) of EEX             $ (6.2)         $32.0           $15.2          $(1.2)         $(34.0)         $36.8
Amortization of costs capitalized by
  ENSERCH not incurred by EEX                (7.0)          (6.3)           (9.0)          (6.5)           (6.9)          (4.4)
Write-down of capitalized cost under
  the full-cost ceiling limitation
  by EEX not required by ENSERCH                                                                           52.0
Litigation judgment against ENSERCH                                        (41.4)
Effects of intercompany lease
  transactions                                2.5
Activities not conducted through EEX         (0.8)          (0.1)           (2.1)           1.5            (0.2)          (0.5)
                                           ------          -----          ------          -----           -----          -----
Operating income (loss) of ENSERCH's
  natural gas and oil exploration and
  production segment                       $(11.5)         $25.6         $(37.3)         $(6.2)           $10.9          $31.9

--------------------------------------
<FN>
(a)    Oil and natural gas liquids are converted to Mcf equivalents (Mcfe) on the basis of one barrel equals 6.0 Mcfe.
(b)    Excludes production, severance and ad valorem taxes.
</FN>
</TABLE>

                                A-13
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
         NATURAL GAS PIPELINE & GATHERING, PROCESSING AND MARKETING OPERATING DATA (a)



                                                                         For Year Ended December 31
                                        -------------------------------------------------------------------------------------
                                             1995          1994           1993            1992            1991           1990
                                        -------------------------------------------------------------------------------------

<S>                                         <C>         <C>               <C>            <C>             <C>            <C>
Operating Income (in millions)
  Pipeline . . . . . . . . . . . . . .      $ 49.3      $   25.1          $ 51.7         $ 41.2          $ 45.0         $ 31.9
  Natural Gas Marketing. . . . . . . .         6.1            .9            16.7           13.4            12.5           15.8
  Natural Gas Processing . . . . . . .         4.2           1.0             5.0           13.1            21.2           24.9
                                            ------      --------          ------         ------          ------         ------
    Total. . . . . . . . . . . . . . .      $ 59.6      $   27.0          $ 73.4         $ 67.7          $ 78.7         $ 72.6

Revenues (in millions)
  Pipeline (b) . . . . . . . . . . . .      $143.5      $  141.0          $143.4         $135.9          $185.6         $193.1
  Natural Gas Marketing. . . . . . . .       750.5         997.4           666.2          406.7           297.9          287.3
  Natural Gas Processing -
    Natural gas liquids (c). . . . . .        69.7          68.9            73.6           79.0            84.9           91.8
  Other (d). . . . . . . . . . . . . .        32.7          28.5            24.8           17.9            22.0           21.4
                                            ------      --------          ------         ------          ------         ------
    Total revenues . . . . . . . . . .      $996.4      $1,235.8          $908.0         $639.5          $590.4         $593.6

Volumes
  Pipeline throughput (Bcf). . . . . .       561.1         541.6           542.8          472.9           481.2          437.2
  Natural Gas Marketing (Bcf). . . . .       417.7         488.4           306.7          210.9           173.3          154.7
  Natural Gas Processing (MMBbls). . .         6.0           5.9             6.0            5.9             6.1            6.4

Average Sales Price
  Natural Gas Marketing (per Mcf). . .      $ 1.80      $   2.04          $ 2.17         $ 1.93          $ 1.72         $ 1.86
  Natural Gas Liquids (per Bbl). . . .      $11.66      $  11.65          $12.34         $13.35          $13.92         $14.27

----------------------------
<FN>
(a) Prior year amounts have been restated for the realignment of business segments and the pooling-of-interests transaction with
    DGS.
(b) Includes transportation services for affiliates and third-parties and other miscellaneous revenues.
(c) Represents revenues from sales of plant production.
(d) Includes revenues from natural-gas products purchased for resale, gathering fees and other miscellaneous revenues.
</FN>
</TABLE>
                                A-14
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                                     NATURAL GAS DISTRIBUTION OPERATING DATA


                                                                        For Year Ended December 31
                                          ------------------------------------------------------------------------------------
                                             1995          1994            1993           1992           1991           1990
                                          ------------------------------------------------------------------------------------
<S>                                        <C>           <C>             <C>           <C>              <C>            <C>
Operating Income (in millions) . . . .     $  54.6       $  38.3         $  34.2       $   48.4         $  54.1        $  53.8

Natural Gas Sales Revenues by Customer
 (in millions)
   Residential & commercial. . . . . .     $ 766.5       $ 744.3         $ 823.8       $  716.5         $ 702.9        $ 684.3
   Industrial. . . . . . . . . . . . .        55.7          63.5            69.6           88.9           100.3          114.6
   Electric generation . . . . . . . .        44.5          46.6            52.7           97.5            89.6          110.9
                                           -------       -------         -------       --------         -------        -------
     Total gas sales revenues. . . . .       866.7         854.4           946.1          902.9           892.8          909.8
Gas transportation revenues (a). . . .        11.5          11.3            11.5            9.9            10.0            9.6
Other revenues . . . . . . . . . . . .         9.3           9.0            10.3           10.6            10.4           10.5
                                           -------       -------         -------       --------         -------        -------
     Total revenues. . . . . . . . . .     $ 887.5       $ 874.7         $ 967.9       $  923.4         $ 913.2        $ 929.9

Natural Gas Sales Volumes by Customer
 (Bcf)
   Residential & commercial. . . . . .       125.7         125.7           139.3          120.6           128.5          122.6
   Industrial. . . . . . . . . . . . .        13.6          15.3            16.9           20.3            25.8           28.3
   Electric generation . . . . . . . .        11.0          11.0            12.4           21.3            23.3           26.7
                                           -------       -------         -------       --------         -------        -------
     Total gas sales volumes . . . . .       150.3         152.0           168.6          162.2           177.6          177.6

Natural Gas Sales Revenues (per Mcf)
   Residential & commercial. . . . . .     $  6.10      $   5.92         $  5.91       $   5.94         $  5.47        $  5.58
   Industrial. . . . . . . . . . . . .        4.11          4.16            4.12           4.37            3.90           4.06
   Electric generation . . . . . . . .        4.04          4.24            4.26           4.56            3.85           4.15

Natural Gas Purchase Cost (per Mcf). .     $  4.07      $   4.05         $  4.13       $   4.10         $  3.67        $  3.81

Heating Degree Days. . . . . . . . . .       2,173         2,201           2,508          1,980           2,179          2,015
   % of normal (2,407) . . . . . . . .        90.3          91.4           104.2           82.3            90.5           83.7
Cooling Degree Days. . . . . . . . . .       2,656         2,676           2,767          2,415           2,670          2,791
   % of normal (2,603) . . . . . . . .       102.0         102.8           106.3           92.8           102.6          107.2

--------------------------
<FN>
(a) Represents the portion of transportation revenues attributable to the distribution system.  Related volumes are included
    within Natural Gas Pipeline & Gathering, Processing and Marketing statistics.
</FN>
</TABLE>

                                A-15
<PAGE>
<PAGE>
INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of Directors of ENSERCH Corporation:


     We have audited the accompanying consolidated balance sheets of ENSERCH
Corporation and subsidiary companies as of December 31, 1995 and 1994, and the
related statements of consolidated income, cash flows and common shareholders'
equity for each of the three years in the period ended December 31, 1995.
These financial statements are the responsibility of the Corporation's
management.  Our responsibility is to express an opinion on these financial
statements based on our audits.  The consolidated financial statements give
retroactive effect to the combination of ENSERCH Corporation and DGS Holdings
Corp., which has been accounted for as a pooling-of-interests, as described
in Note 2 of the Notes to Consolidated Financial Statements.  We have
previously audited the consolidated balance sheets of ENSERCH Corporation and
subsidiary companies as of December 31, 1993, 1992, 1991 and 1990 and the
related statements of consolidated income, cash flows and common shareholders'
equity for the years ended December 31, 1992, 1991, and 1990 (not presented
herewith), and have expressed unqualified opinions thereon.

     We conducted our audits in accordance with generally accepted auditing
standards.  Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement.  An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audits provide a
reasonable basis for our opinion.

     In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of ENSERCH Corporation and
subsidiary companies at December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1995, in conformity with generally accepted accounting
principles.  Also, in our opinion, the information set forth in the
accompanying table of selected financial data for the years 1990 through 1995
is fairly stated in all material respects in relation to the consolidated
financial statements from which such information has been derived.




DELOITTE & TOUCHE LLP

Dallas, Texas
February 9, 1996




                                A-16
<PAGE>
<PAGE>

MANAGEMENT REPORT ON RESPONSIBILITY FOR FINANCIAL REPORTING




     The management of ENSERCH Corporation is responsible for the preparation,
presentation and integrity of the financial statements and other information
contained in this report.  The financial statements have been prepared in
conformity with accounting principles generally accepted in the United States
and include amounts that represent management's best estimates and judgments.
Management has established practices and procedures designed to support the
reliability of the estimates and minimize the possibility of a material
misstatement.

     Management has established and maintains internal accounting controls
that provide reasonable assurance as to the integrity and reliability of the
financial statements, the protection of assets from unauthorized use or
disposition, and the prevention and detection of fraudulent financial
reporting.  The system of internal control is supported by written policies
and procedures, and the control environment is regularly evaluated by both the
Corporation's internal auditors and Deloitte & Touche LLP, the Corporation's
independent auditors.  The Board of Directors maintains an Audit Committee
composed of Directors who are not employees.  The Audit Committee meets
periodically with management, the independent auditors and the internal
auditors to discuss significant accounting, auditing, internal accounting
control and financial reporting matters.  The independent auditors and the
internal auditors have free access to the Audit Committee.

    Management believes that, as of December 31, 1995, the overall system of
internal accounting controls is sufficient to accomplish the objectives
discussed herein.


/s/ D. W. Biegler         /s/ M. E. Rescoe             /s/ J. W. Pinkerton
--------------------      ------------------------     --------------------
D. W. Biegler             M. E. Rescoe                 J. W. Pinkerton
Chairman, President       Senior Vice President,       Vice President and
and Chief                 Finance, Chief               Controller, Chief
Executive Officer         Financial Officer            Accounting Officer





February 9, 1996



                                A-17
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                             ENSERCH CORPORATION AND SUBSIDIARY COMPANIES

                                   STATEMENTS OF CONSOLIDATED INCOME

                                                                         Year Ended December 31
                                                             ------------------------------------------------
                                                                 1995               1994              1993
                                                             ------------------------------------------------
                                                                 (In thousands except per share amounts)
<S>                                                          <C>                 <C>               <C>
Revenues
  Natural gas and oil exploration and production . . .       $  220,851          $  179,140        $  189,796
  Natural gas pipeline & GPM . . . . . . . . . . . . .          996,451           1,235,763           907,969
  Natural gas distribution . . . . . . . . . . . . . .          887,465             874,707           967,876
  Power and other. . . . . . . . . . . . . . . . . . .           39,817              45,499            48,635
  Less intercompany revenues . . . . . . . . . . . . .         (213,344)           (239,601)         (235,374)
                                                             ----------          ----------        ----------
       Total . . . . . . . . . . . . . . . . . . . . .        1,931,240           2,095,508         1,878,902
                                                             ----------          ----------        ----------
Costs and Expenses
  Gas purchase . . . . . . . . . . . . . . . . . . . .        1,170,732           1,432,301         1,160,416
  Operating expenses . . . . . . . . . . . . . . . . .          405,580             366,512           420,272
  Depreciation and amortization. . . . . . . . . . . .          168,262             126,979           144,326
  Gross receipts and production taxes. . . . . . . . .           51,086              50,723            55,999
  Payroll, ad valorem and other taxes. . . . . . . . .           37,851              30,347            29,652
                                                             ----------          ----------        ----------
       Total . . . . . . . . . . . . . . . . . . . . .        1,833,511           2,006,862         1,810,665
                                                             ----------          ----------        ----------
Operating Income . . . . . . . . . . . . . . . . . . .           97,729              88,646            68,237
Other Income (Expense) - Net . . . . . . . . . . . . .           (1,033)             (6,048)              116
Interest and Other Financing Costs . . . . . . . . . .          (83,324)            (69,310)          (77,720)
                                                             ----------          ----------        ----------
Income (Loss) before Income Taxes
  and Minority Interest. . . . . . . . . . . . . . . .           13,372              13,288            (9,367)
Income Taxes (Benefit) . . . . . . . . . . . . . . . .              921             (68,737)            6,636
Minority Interest. . . . . . . . . . . . . . . . . . .             (602)                573                34
                                                             ----------          ----------        ----------
Income (Loss) from Continuing Operations . . . . . . .           13,053              81,452           (16,037)
Income from Discontinued Operations  . . . . . . . . .                               20,642            75,418
                                                             ----------          ----------        ----------
Net Income . . . . . . . . . . . . . . . . . . . . . .           13,053             102,094            59,381
Provision for Dividends on Preferred Stock . . . . . .           11,690              11,619            12,663
                                                             ----------          ----------        ----------
Earnings Applicable to Common Stock. . . . . . . . . .       $    1,363          $   90,475        $   46,718
                                                             ==========          ==========        ==========
Per Share of Common Stock
  Income (loss) from continuing operations
    after provision for dividends on
    preferred stock. . . . . . . . . . . . . . . . . .       $      .02          $     1.03        $     (.42)
  Discontinued operations. . . . . . . . . . . . . . .                                  .30              1.11
                                                             ----------          ----------        ----------
  Earnings applicable to common stock. . . . . . . . .       $      .02          $     1.33        $      .69
                                                             ==========          ==========        ==========
  Cash dividends declared. . . . . . . . . . . . . . .       $      .20          $      .20        $      .20
                                                             ==========          ==========        ==========
Average Common and Dilutive Common
  Equivalent Shares Outstanding. . . . . . . . . . . .           68,323              68,049            67,802
                                                             ==========          ==========        ==========
Operating Income (Loss) of Major Business Segments
  (Excludes general corporate expenses)
  Natural gas and oil exploration and production . . .       $  (11,450)         $   25,617        $  (37,293)
  Natural gas pipeline & GPM . . . . . . . . . . . . .           59,580              27,048            73,425
  Natural gas distribution . . . . . . . . . . . . . .           54,634              38,334            34,175
  Power and other. . . . . . . . . . . . . . . . . . .            3,478               5,761             9,795
<FN>
See Notes to Consolidated Financial Statements.
</FN>
</TABLE>
                                               A-18
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                                ENSERCH CORPORATION AND SUBSIDIARY COMPANIES

                                    STATEMENTS OF CONSOLIDATED CASH FLOWS
                                                                                     Year Ended December 31
                                                                        ----------------------------------------------
                                                                           1995              1994               1993
                                                                        ----------------------------------------------
                                                                                        (In thousands)
<S>                                                                       <C>               <C>               <C>
OPERATING ACTIVITIES
  Income (loss) from continuing operations . . . . . . . . . . . . .      $ 13,053          $ 81,452          $(16,037)
  Depreciation and amortization. . . . . . . . . . . . . . . . . . .       168,262           126,979           144,326
  Deferred income-tax benefit. . . . . . . . . . . . . . . . . . . .        (5,680)          (59,151)             (847)
  Recoveries of gas-purchase contract settlements. . . . . . . . . .        51,297            49,602            50,825
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         7,283            (2,544)           (5,548)
  Changes in current operating assets and liabilities
    Accounts receivable. . . . . . . . . . . . . . . . . . . . . . .       (31,476)           13,038           (17,988)
    Other current assets . . . . . . . . . . . . . . . . . . . . . .        13,087           (34,014)          (13,645)
    Accounts payable . . . . . . . . . . . . . . . . . . . . . . . .        18,503            (2,142)           51,465
    Other current liabilities. . . . . . . . . . . . . . . . . . . .        18,332           (20,041)          (36,153)
    Litigation judgment payable. . . . . . . . . . . . . . . . . .                           (62,498)           47,032
                                                                          --------          --------          --------
      Net Cash Flows from Operating Activities . . . . . . . . . . .       252,661            90,681           203,430
                                                                          --------          --------          --------
INVESTING ACTIVITIES
  Purchases of businesses, net of cash acquired. . . . . . . . . . .      (348,607)             (122)              508
  Additions of property, plant and equipment . . . . . . . . . . . .      (297,026)         (260,058)         (218,693)
  Retirements of property, plant and equipment . . . . . . . . . . .        59,699            16,756            15,211
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       (19,225)            7,005            (2,711)
                                                                         ---------          --------          --------
      Net Cash Flows used for Investing Activities . . . . . . . . .      (605,159)         (236,419)         (205,685)
                                                                         ---------          --------          --------
FINANCING ACTIVITIES
  Change in commercial paper and other short-term borrowings . . . .        32,759           116,271          (118,842)
  Borrowing under EEX bank revolving credit agreement and
    bridge loan. . . . . . . . . . . . . . . . . . . . . . . . . . .       530,000
  Repayment of DALEN bank debt assumed at acquisition. . . . . . . .      (115,000)
  Issuance of mandatorily redeemable preferred securities
    of subsidiary. . . . . . . . . . . . . . . . . . . . . . . . . .       150,000
  Issuance of EEX common stock . . . . . . . . . . . . . . . . . . .       207,872
  Retirement of EEX revolving credit agreement and
    bridge loan. . . . . . . . . . . . . . . . . . . . . . . . . . .      (370,000)
  Issuance of senior long-term debt. . . . . . . . . . . . . . . . .       150,000           300,145           200,008
  Debt issuance costs. . . . . . . . . . . . . . . . . . . . . . . .          (944)             (883)
  Retirement of senior long-term debt and
    convertible debentures . . . . . . . . . . . . . . . . . . . . .      (162,677)         (214,983)         (423,523)
  Settlement of foreign currency swap. . . . . . . . . . . . . . . .                                            23,089
  Issuance of Series F Preferred Stock . . . . . . . . . . . . . . .                          72,797
  Retirement of Series D Preferred Stock . . . . . . . . . . . . . .                         (75,000)
  Change in advances under lease arrangements. . . . . . . . . . . .         9,883           (32,157)           13,571
  Change in assignments of future gas purchase credits . . . . . . .       (17,191)          (21,000)          (15,923)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          (784)                1             3,988
  Issuance of ENSERCH common stock . . . . . . . . . . . . . . . . .         4,408             3,451            10,876
  Cash dividends paid. . . . . . . . . . . . . . . . . . . . . . . .       (25,401)          (25,071)          (25,967)
                                                                          --------         ---------          --------
      Net Cash Flows from (used for) Financing Activities. . . . . .       392,925           123,571          (332,723)
                                                                          --------         ---------          --------
Net Cash Flows from (used for) Discontinued Operations . . . . . .         (28,102)             (942)          318,408
                                                                          --------         ---------          --------
Net Increase (Decrease) in Cash and Equivalents. . . . . . . . . . .        12,325           (23,109)          (16,570)
Cash and Equivalents at Beginning of Year. . . . . . . . . . . . . .         9,811            32,920            49,490
                                                                          --------          --------          --------
Cash and Equivalents at End of Year. . . . . . . . . . . . . . . . .      $ 22,136          $  9,811          $ 32,920
                                                                          ========          ========          ========
Amounts paid (refunded)
  Interest and other financing costs (net of amount capitalized) . .      $ 99,182          $ 66,926          $101,549
                                                                          ========          ========          ========
Income taxes - net . . . . . . . . . . . . . . . . . . . . . . . . .      $ (5,659)         $  5,245          $ 20,900
                                                                          ========          ========          ========
Purchases of businesses
  Fair value of assets acquired. . . . . . . . . . . . . . . . . .        $502,955                            $  7,793
  Cash paid for acquisitions . . . . . . . . . . . . . . . . . . .         348,607                                (508)
                                                                          --------                            --------
  Liabilities assumed. . . . . . . . . . . . . . . . . . . . . . .        $151,348                            $  8,301
                                                                          ========                            ========
<FN>
See Notes to Consolidated Financial Statements.
</FN>
</TABLE>
                                                A-19
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                           ENSERCH CORPORATION AND SUBSIDIARY COMPANIES

                                  CONSOLIDATED BALANCE SHEETS
                                                                          December 31
                                                                  --------------------------
                                                                       1995           1994
                                                                  --------------------------
                                                                        (In thousands)
<S>                                                                <C>            <C>
ASSETS
Current Assets
  Cash and equivalents. . . . . . . . . . . . . . . . . . . .      $   22,136     $    9,811
  Accounts receivable . . . . . . . . . . . . . . . . . . . .         296,178        224,500
  Gas stored underground. . . . . . . . . . . . . . . . . . .         107,633        114,862
  Prepayments for gas and recoverable
    gas-purchase settlements. . . . . . . . . . . . . . . . .           7,047         52,565
  Other . . . . . . . . . . . . . . . . . . . . . . . . . . .         100,922        128,706
                                                                   ----------     ----------
    Total current assets. . . . . . . . . . . . . . . . . . .         533,916        530,444
                                                                   ----------     ----------
Investments . . . . . . . . . . . . . . . . . . . . . . . . .          64,974         56,165
                                                                   ----------     ----------
Property, Plant and Equipment (at cost)
  Natural gas and oil exploration and production (full-cost
    method) . . . . . . . . . . . . . . . . . . . . . . . . .       2,581,737      2,070,318
  Natural gas pipeline & gathering, processing
    and marketing . . . . . . . . . . . . . . . . . . . . . .         827,913        775,962
  Natural gas distribution. . . . . . . . . . . . . . . . . .         948,076        898,361
  Power and other . . . . . . . . . . . . . . . . . . . . . .          32,702         32,186
  General and other . . . . . . . . . . . . . . . . . . . . .          23,761         26,672
                                                                   ----------     ----------
    Total . . . . . . . . . . . . . . . . . . . . . . . . . .       4,414,189      3,803,499
  Less accumulated depreciation and amortization. . . . . . .       1,687,409      1,550,014
                                                                   ----------     ----------
    Net property, plant and equipment . . . . . . . . . . . .       2,726,780      2,253,485
                                                                   ----------     ----------
Other Assets. . . . . . . . . . . . . . . . . . . . . . . . .          55,424         48,443
                                                                   ----------     ----------
      Total . . . . . . . . . . . . . . . . . . . . . . . . .      $3,381,094     $2,888,537
                                                                   ==========     ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
  Commercial paper and other short-term borrowings. . . . . .      $  187,000     $  154,241
  Current portion of senior long-term debt. . . . . . . . . .          14,760         10,600
  Accounts payable. . . . . . . . . . . . . . . . . . . . . .         329,844        331,920
  Accrued interest. . . . . . . . . . . . . . . . . . . . . .          22,436         35,885
  Other current liabilities . . . . . . . . . . . . . . . . .         123,212         95,635
  Liabilities for discontinued operations . . . . . . . . . .          42,120         59,259
                                                                   ----------     ----------
    Total current liabilities . . . . . . . . . . . . . . . .         719,372        687,540
                                                                   ----------     ----------
Senior Long-term Debt . . . . . . . . . . . . . . . . . . . .         870,476        715,721
                                                                   ----------     ----------
Convertible Subordinated Debentures . . . . . . . . . . . . .          90,750         90,750
                                                                   ----------     ----------
Other Liabilities
  Deferred income taxes . . . . . . . . . . . . . . . . . . .         277,076        280,051
  Accrued pension costs . . . . . . . . . . . . . . . . . . .          54,959         53,617
  Other . . . . . . . . . . . . . . . . . . . . . . . . . . .         167,845        147,570
                                                                   ----------     ----------
    Total other liabilities . . . . . . . . . . . . . . . . .         499,880        481,238
                                                                   ----------     ----------
Mandatorily Redeemable Preferred Securities
  of Subsidiary of EEX. . . . . . . . . . . . . . . . . . . .         150,000
                                                                   ----------     ----------
Minority Interest in Subsidiaries . . . . . . . . . . . . . .         156,434         12,101
                                                                   ----------     ----------
Commitments and Contingent Liabilities (Note 7) . . . . . . .

Shareholders' Equity
  Adjustable rate preferred stock . . . . . . . . . . . . . .         175,000        175,000
  Common shareholders' equity . . . . . . . . . . . . . . . .         719,182        726,187
                                                                   ----------     ----------
    Shareholders' equity. . . . . . . . . . . . . . . . . . .         894,182        901,187
                                                                   ----------     ----------
       Total. . . . . . . . . . . . . . . . . . . . . . . . .      $3,381,094     $2,888,537
                                                                   ==========     ==========
<FN>
See Notes to Consolidated Financial Statements.
</FN>
</TABLE>
                                                  A-20
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                         ENSERCH CORPORATION AND SUBSIDIARY COMPANIES

                   STATEMENTS OF CONSOLIDATED COMMON SHAREHOLDERS' EQUITY

                                                                          Year Ended December 31
                                                                 ------------------------------------------
                                                                    1995            1994             1993
                                                                 ------------------------------------------
                                                                             (In thousands)
<S>                                                              <C>              <C>              <C>
Common Stock - $4.45 par value, authorized 100 million shares
  Balance at beginning of year . . . . . . . . . . . . . .       $303,301         $301,977         $299,207
    Issued for stock plans (358; 298; and 622 shares). . .          1,596            1,324            2,770
                                                                 --------         --------         --------
  Balance at end of year (Outstanding shares:
    68,516; 68,158; and 67,860). . . . . . . . . . . . . .        304,897          303,301          301,977
                                                                 --------         --------         --------
Paid in Capital
  Balance at beginning of year . . . . . . . . . . . . . .        334,672          333,768          348,442
    Excess of proceeds over par value of
      common stock issued for stock plans. . . . . . . . .          4,185            3,107            8,106
    Dividends declared in excess of retained earnings. . .                                          (22,780)
    Series F preferred stock issuance costs. . . . . . . .                          (2,203)
                                                                 --------         --------         --------
   Balance at end of year. . . . . . . . . . . . . . . . .        338,857          334,672          333,768
                                                                 --------         --------         --------
Retained Earnings (Deficit)
  Balance at beginning of year . . . . . . . . . . . . . .         89,054           11,913          (44,307)
    Net income . . . . . . . . . . . . . . . . . . . . . .         13,053          102,094           59,381
    Dividends declared . . . . . . . . . . . . . . . . . .        (25,162)         (24,952)         (25,939)
    Transfer of dividends declared in excess of
      retained earnings to paid in capital . . . . . . . .                                           22,780
    Other. . . . . . . . . . . . . . . . . . . . . . . . .             (4)              (1)              (2)
                                                                 --------         --------         --------
  Balance at end of year . . . . . . . . . . . . . . . . .         76,941           89,054           11,913
                                                                 --------         --------         --------
Unamortized Restricted Stock Compensation
 Balance at beginning of year. . . . . . . . . . . . . . .           (840)
   Shares granted (59 and 89). . . . . . . . . . . . . . .           (865)          (1,261)
   Cancellations (5 and 14). . . . . . . . . . . . . . . .             64              192
   Amortization. . . . . . . . . . . . . . . . . . . . . .            460              140
   Market valuation adjustments. . . . . . . . . . . . . .           (332)              89
                                                                 --------         --------
 Balance at end of year. . . . . . . . . . . . . . . . . .         (1,513)            (840)
                                                                 --------         --------         --------
Common Shareholders' Equity. . . . . . . . . . . . . . . .       $719,182         $726,187         $647,658
                                                                 ========         ========         ========



<FN>
See Notes to Consolidated Financial Statements.
</FN>
</TABLE>
                                A-21
<PAGE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All dollar amounts, except per share amounts, in the notes to consolidated
financial statements are stated in thousands unless otherwise indicated.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER INFORMATION

The consolidated financial statements include the accounts of ENSERCH
Corporation (ENSERCH or the Corporation) and its majority-owned subsidiaries.
Information by business segments is presented elsewhere herein and is an
integral part of these financial statements.  The preparation of financial
statements requires the use of significant estimates and assumptions by
management; actual results could differ from those estimates.

The financial statements for years prior to 1995 have been restated to include
the historical results of DGS Holdings Corp. (DGS) following a pooling-of-
interests transaction effective June 30, 1995 (see Note 2).

Prior-period results also have been restated to reflect a realignment of
business segments.  The pipeline and gas marketing operations, formerly
reported under the natural gas transmission and distribution segment, and the
gas processing operations, formerly reported separately as the natural gas
liquids processing segment, are now combined as the natural gas pipeline &
gathering, processing and marketing (GPM) business segment.  Distribution
utility operations are now reported as the natural gas distribution segment.

Earnings per share applicable to common stock are based on the weighted
average number of common shares outstanding during the year, including common
equivalent shares when dilutive.  Fully diluted earnings per share are not
presented since the assumed exercise of stock options and conversion of
debentures would not be dilutive.

All highly liquid investments purchased in the United States with a maturity
of three months or less at date of purchase are considered to be cash
equivalents.

Derivative Instruments - The Corporation frequently enters into swaps,
futures, options and other derivative contracts in connection with its natural
gas marketing activities conducted by Enserch Energy Services, Inc. (EES) or
to hedge the impact of market fluctuations in gas and oil prices on
anticipated future gas and oil production of Enserch Exploration, Inc. (EEX)
or other contractual commitments.  The Corporation defers the impact of
changes in the market value of contracts that serve as hedges until the
related transaction is completed.  The Corporation also enters into interest-
rate swaps to manage risk associated with interest rates and reduce the
Corporation's exposure to interest rate fluctuations.  Interest-rate swaps are
valued on a periodic basis, with resulting differences deferred and recognized
as an adjustment to interest and other financing costs over the term of the
agreement.

                                A-22
<PAGE>
<PAGE>
Natural Gas and Oil Exploration and Production - The full-cost accounting
method prescribed by the Securities and Exchange Commission (SEC) is followed
for gas and oil properties.  Under this method, all acquisition, exploration
and development costs incurred, including salaries, benefits and other
internal costs directly attributable to these activities, are capitalized.
All costs associated with production and general corporate activities are
expensed  in  the  period  incurred.  Costs  directly associated with the
acquisition and evaluation of unproved gas and oil properties are excluded
from the amortization base until the related properties are evaluated.  Such
unproved properties are assessed periodically and a provision for impairment
is made to the full-cost amortization base when appropriate. Amortization of
evaluated gas and oil properties is computed on the unit-of-production method
using estimated proved gas and oil reserves quantified on the basis of their
equivalent energy content.  Amortization of gas and oil properties was
approximately 6.0% in 1995, 5.8% in 1994 and 6.0% in 1993.  Depreciation of
other property, plant and equipment is provided principally by the straight-
line method over the estimated service lives of the related assets.  At
December 31, 1995, estimates of future site restoration, dismantlement and
abandonment costs, as assessed on an overall cost center basis, were less than
estimates of future salvage values.  Therefore, no accruals were required.

Natural Gas Pipeline & GPM - Lone Star Pipeline Company (Lone Star Pipeline
or LSP) is subject to regulatory utility accounting requirements.  Pipeline
revenues consist of the transportation charge to Lone Star Gas Company (Lone
Star Gas or LSG) and transportation revenues from unaffiliated customers.  The
transportation rate charged to LSG for gas ultimately consumed by residential
and commercial customers is established by the Railroad Commission of Texas.
The pipeline system is generally depreciated by the straight-line method over
approximately 40 years.  Gas stored underground is valued at average cost.

Natural Gas Distribution - Lone Star Gas is also subject to regulatory utility
accounting requirements.  LSG city gate rate for the cost of gas ultimately
delivered to residential and commercial customers is established by the
Railroad Commission of Texas and provides for full recovery of the actual cost
of gas delivered, including out-of-period costs such as gas-purchase contract
settlement costs.  LSG's rates to residential and commercial customers are
established by the municipal governments of the cities and towns served, with
the Railroad Commission of Texas having appellate jurisdiction.  Lone Star Gas
records revenues on the basis of cycle meter readings throughout the month and
accrues revenues for gas delivered from the meter reading dates to the end of
the month.  The distribution system is depreciated by the straight-line method
over approximately 40 years.

2.   CHANGE IN ORGANIZATION, ACQUISITIONS AND DISPOSITIONS

Prior to December 30, 1994, ENSERCH's 99.2% ownership of Enserch Exploration
Partners, Ltd. (EP) was held primarily through Enserch Processing Partners
Limited (EPPL).  On December 30, 1994, EEX acquired all of the partnership
interests of EP Operating Limited Partnership (EPO), the operating partnership
of EP in which EP owned a 99% interest and other ENSERCH companies owned a 1%
interest.  EPO was then merged into EEX and thereafter, EP was liquidated.
Following the liquidation of EP, EPPL redeemed ENSERCH's interest in EPPL in
exchange for EEX stock and EPPL's operating assets.  In 1995, ENSERCH sold its

                                A-23
<PAGE>
<PAGE>
international gas and oil operations and its SACROC operations to EEX for
1,240,000 shares of EEX common stock and $4.2 million in cash.

On June 8, 1995, EEX acquired all the capital stock of DALEN Corporation
(DALEN) for cash of $340 million and assumed DALEN's bank debt of $115
million.  The acquisition was accounted for as a purchase.  The assets
acquired and the liabilities assumed were recorded at their estimated fair
value pending final evaluation.  Essentially all of the valuation adjustment
was assigned to gas and oil properties.

Following is a summary of pro forma results of operations assuming the DALEN
acquisition had occurred at the beginning of the periods presented:
<TABLE>
<CAPTION>
                                                                      Year Ended December 31
                                                                   ---------------------------
                                                                      1995             1994
                                                                   ----------       ----------
     <S>                                                           <C>              <C>
     Revenues. . . . . . . . . . . . . . . . . . . . . . . .       $1,979,564       $2,238,904
     Operating Income. . . . . . . . . . . . . . . . . . . .           97,272          108,879
     Net Income. . . . . . . . . . . . . . . . . . . . . . .            2,793           91,652
     Earnings (Loss) Applicable to Common Stock. . . . . . .           (8,897)          80,033
     Earnings (Loss) Applicable to Common Stock - per share.             (.13)            1.18
</TABLE>
At June 30 and September 30, 1995, ENSERCH's full-cost ceiling amount
attributable to the properties acquired in the DALEN acquisition was
significantly less than the unamortized cost of producing properties acquired,
but at December 31, 1995, the ceiling amount exceeded costs by some $19
million.  ENSERCH believes that the acquired properties have significant
exploration and development potential.  ENSERCH expects to be able to utilize
its expertise, particularly with respect to tight sands reservoirs, to enhance
production and cash flows from these properties because of the geologic
similarity and proximity of the major producing properties to ENSERCH's other
properties.  ENSERCH believes that the unamortized cost of the gas and oil
properties acquired is recoverable from future production.  ENSERCH requested
and was granted a waiver of the full-cost ceiling limitation on these
properties by the SEC through June 30, 1996.  If an excess exists after that
date, a write-down may be required.

On September 26, 1995, EEX sold 20 million shares of its common stock to the
public for net proceeds of approximately $208 million, and ENSERCH's ownership
percentage was reduced from 99.2% to 83.4%.  As a result of the stock sale,
ENSERCH's equity interest in EEX, after the reduction in ownership percentage,
increased $59 million.  In accordance with the full-cost accounting method,
ENSERCH credited the $59 million to the carrying value of gas and oil
properties, with no gain recognized on the sale since the sale did not
significantly alter the relationship between capitalized costs and proved
reserves.

On June 29, 1995, ENSERCH purchased the principal operating assets of Sunrise
Energy Services, Inc. and subsidiaries (Sunrise), a nonregulated marketer of
natural gas, for approximately $9 million in cash, including some $8 million
of cost in excess of net assets acquired.  The acquisition was accounted for
as a purchase.  The goodwill is being amortized over 20 years.  The acquired
Sunrise  operations  had  revenues  of approximately $76 million for the six
months ended June 30, 1995 and $232 million for the year ended December 31,
1994.  Operating results of the Sunrise operations for these periods were not

                                A-24
<PAGE>
<PAGE>
significant.  The Sunrise operations do not constitute a significant
acquisition; therefore, pro forma information is not presented.

Operations of DALEN and Sunrise have been included in the accompanying
consolidated financial statements from their respective dates of acquisition.

Effective June 30, 1995, the Corporation exchanged 1,204,098 shares of ENSERCH
common stock for 100% of the outstanding shares of DGS, which, through its
subsidiary, is a major marketer of natural gas and natural-gas services.  The
transaction was accounted for as a pooling-of-interests. Accordingly, the
Corporation's financial statements have been restated for all periods
presented to include DGS in the natural gas pipeline & GPM segment.  Common
stock at the beginning of 1993 has been increased by $5.4 million to reflect
the par value of shares issued, paid in capital has been reduced by $5.3
million for the excess of the par value over net assets acquired, and retained
earnings has been increased by $.8 million for the retained earnings of DGS.
Operating results of DGS for the periods preceding the acquisition were as
follows:
<TABLE>
<CAPTION>
                                                                           Year Ended
                                                                          December 31
                                                    Six Months Ended  --------------------
                                                      June 30, 1995     1994        1993
                                                     -------------    --------    --------
     <S>                                               <C>            <C>         <C>
     Revenues                                          $120,030       $238,077    $145,701
     Net Income (Loss)                                      527           (223)        144

</TABLE>
DGS's net income for the 1995 and 1994 periods was impacted by significant
financing costs that are not incurred under ENSERCH ownership.  The 1994
results reflect significant severance and other costs relating to an
acquisition.

3.  BORROWINGS AND LINES OF CREDIT
<TABLE>
<CAPTION>
   Senior Long-term Debt at December 31:                                  1995             1994
                                                                        --------        --------
    <S>                                                                 <C>             <C>
    8% Notes due 1997. . . . . . . . . . . . . . . . . . . . . . .      $100,000        $100,000
    Variable rate note due 1998 (Interest based on LIBOR). . . . .                       150,000
    7% Notes due 1999. . . . . . . . . . . . . . . . . . . . . . .       150,000         150,000
    9.06% Notes due 1996 through 1999. . . . . . . . . . . . . . .        65,600          76,200
    EEX Bank Revolving Credit Agreement Maturing 1999. . . . . . .       160,000
    8 7/8% Notes due 2001  . . . . . . . . . . . . . . . . . . . .       100,000         100,000
    6 3/8% Notes due 2004. . . . . . . . . . . . . . . . . . . . .       150,000         150,000
    7 1/8% Notes due 2005. . . . . . . . . . . . . . . . . . . . .       150,000
    Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . .         9,636             121
                                                                        --------        --------
      Total. . . . . . . . . . . . . . . . . . . . . . . . . . . .       885,236         726,321
    Less current maturities. . . . . . . . . . . . . . . . . . . .        14,760          10,600
                                                                        --------        --------
      Noncurrent . . . . . . . . . . . . . . . . . . . . . . . . .      $870,476        $715,721
                                                                        ========        ========
</TABLE>
<TABLE>
<CAPTION>
                                    1996         1997           1998         1999        2000
                                  -------       -------        ------       -------     -------
    <S>                           <C>           <C>            <C>         <C>          <C>
    Maturities                    $14,760       $119,000       $19,300     $329,500     $4,500
</TABLE>

                                A-25
<PAGE>
<PAGE>
EEX has a $350 million revolving credit line that matures on May 1, 1999, of
which $190 million was unused at December 31, 1995.  The interest rate ranges
from LIBOR (5.94% in effect at December 31, 1995) plus .35% to .75% per annum,
plus a facility fee of from .15% to .25% per annum, depending upon EEX's
consolidated capitalization ratio.

The convertible subordinated debentures have an interest rate of 6 3/8%, are
due in 2002 and are convertible into common stock at $26.88 per share (equal
to 37.20 shares per $1 thousand principal amount).  The debentures may be
redeemed at 102.55% of the principal amount, plus accrued interest, through
March 31, 1996 and at declining premiums thereafter.

Lines of credit are maintained that provide for short- and interim-term
borrowings and also support commercial paper borrowings.  The aggregate lines
of credit totaled $600 million at December 31, 1995, all unused, and expire
in 1997.  All lines are on a fee basis and none require compensating balances
or restrict the use of cash.  All lines provide for borrowing at prevailing
market rates.

Commercial paper totaled $187 million at December 31, 1995 and $151 million
at year-end 1994.  The weighted average interest rate in effect on commercial
paper borrowings at December 31, 1995 and 1994, was 6.0% and 6.3%,
respectively.
<TABLE>
<CAPTION>

Interest and Other Financing Costs:                               1995          1994            1993
                                                               --------       --------        --------
<S>                                                            <C>            <C>             <C>
Interest costs incurred. . . . . . . . . . . . . . . .         $ 85,118       $ 74,260        $ 82,181(a)
Dividends on preferred
  securities of subsidiary . . . . . . . . . . . . . .            4,123
Interest capitalized . . . . . . . . . . . . . . . . .           (5,917)        (4,950)         (4,461)
                                                               --------       --------        --------
Interest charged to expense. . . . . . . . . . . . .           $ 83,324       $ 69,310        $ 77,720(a)
                                                               ========       ========        ========
<FN>
(a) Includes interest not related to borrowings of $8.2 million.
</FN>
</TABLE>
4.   MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY

On August 4, 1995, a subsidiary ("Issuer") of EEX, completed the private
placement of $150 million of adjustable rate mandatorily redeemable preferred
securities for which EEX is also obligated.  The dividends on the preferred
securities are based on LIBOR plus .696% and are reflected in interest and
other financing costs in the statements of consolidated income.  In November
1995, EEX entered into an interest-rate swap to effectively fix the rate for
the dividend on these preferred securities at 6.49% (see Note 6).  The
mandatory redemption date for Issuer's preferred securities is August 4, 2005
or earlier under certain conditions.

                                A-26
<PAGE>
<PAGE>
5.   SHAREHOLDERS' EQUITY

As of December 31, 1995, 7,686,244 shares of unissued common stock were
reserved for issuance under stock plans and conversion of convertible
subordinated debentures.  The Corporation is authorized to issue up to
2,000,000 shares of preferred stock and 2,000,000 shares of voting preference
stock.
<TABLE>
<CAPTION>

Adjustable Rate
 Preferred Stock                         Stated Value Per           Shares Outstanding
at December 31, 1995 and 1994:      -----------------------       -----------------------
-----------------------------       Preferred    Depositary       Preferred    Depositary
                                       Share         Share          Shares      Shares         Amount
                                      ------       -------          ------     ---------      --------
  <S>                                 <C>             <C>          <C>         <C>            <C>
  Series E . . . . . . . . . . .      $1,000          $100         100,000     1,000,000      $100,000
  Series F . . . . . . . . . . .       1,000            25          75,000     3,000,000        75,000
                                                                                              --------
     Total . . . . . . . . . . .                                                              $175,000
                                                                                              ========
</TABLE>
The Series E stock is redeemable at the option of the Corporation at stated
value at any time and the Series F stock is redeemable at stated value after
May 1, 1999.  Holders of the preferred stock are entitled to its stated value
upon involuntary liquidation.

Dividend  rates  are  determined  quarterly,  in  advance,  based  on  the
"Applicable Rate" (highest of the three-month Treasury bill rate, the Treasury
ten-year constant maturity rate and either the Treasury twenty-year or thirty-
year constant maturity rate, as defined), as set forth below:
<TABLE>
<CAPTION>

                                                           Per Annum Rate (Determined Quarterly)
                                                          ---------------------------------------
                                                             Series E                   Series F
                                                          --------------             ------------
<S>                                                       <C>                        <C>
Dividend rate                                              1.20% below                  87% of
                                                          Applicable Rate            Applicable Rate
Minimum rate                                                   7.00%                    4.50%
Maximum rate                                                  13.00%                   10.50%
</TABLE>

<TABLE>
<CAPTION>
  Dividends Declared:                                            1995           1994          1993
                                                               -------        --------      --------
  <S>                                                          <C>           <C>            <C>
  Adjustable Rate Preferred Stock:
    Series D (redeemed in 1994)($.42, $3.77 per share) . .     $             $   625        $ 5,653
    Series E ($7.00, $7.00, $7.00 per depositary share). . .    7,000          7,000          7,000
    Series F ($1.54, $1.32 per depositary share) . . . . . .    4,610          3,955
  Common Stock ($.20, $.20, $.20 per share). . . . . . . . .   13,552         13,372         13,286
                                                              -------        -------        -------
    Total. . . . . . . . . . . . . . . . . . . . . . . . . .  $25,162        $24,952        $25,939
                                                              =======        =======        =======
</TABLE>
Dividends - Restrictions on the payment of dividends on common stock (other
than stock dividends) or acquisitions of capital stock are contained in a loan
agreement relating to senior long-term debt and in the Restated Articles of
Incorporation.  At December 31, 1995, the amount of dividends on common stock
that could be paid under the most restrictive of these agreements exceeded the
retained earnings and paid in capital of the Corporation.

                                A-27
<PAGE>
<PAGE>
Shareholder Rights Plan - The outstanding shares of common stock include one
voting preference stock contingent purchase right, which is exercisable only
under specific conditions.  Under those conditions, each right could be
exercised to purchase one two-hundredth share of a new series of voting
preference stock at an exercise price of $60 or will entitle its holder to
purchase, at a specified exercise price, shares of the Corporation's common
stock (or, in certain circumstances as determined by the Board of Directors,
other consideration) having a value of twice the right's exercise price.  The
rights have no voting privileges, expire on May 5, 1996 and are generally
redeemable at $.05 per right until the 15th day following public announcement
that a 20% position has been acquired.

Stock Options - Stock options have been awarded to key employees and are
outstanding under three plans.  Options for 9,055 shares granted under a
former plan have an exercise option price equal to par value ($4.45).  Options
granted under the other plans have an exercise price of not less than the fair
market value of the common stock on its grant date.  At December 31, 1995,
there were 130 participants in the stock option plans.  Options become
exercisable over four years and generally expire ten years after the date of
the grant.
<TABLE>
<CAPTION>

Summary of Stock Option Activity:                               Number of Options
                                                               ------------------------------------------
                                             1995 Price Range        1995          1994           1993
                                             ----------------- --------------  ------------  -------------
<S>                                            <C>                <C>           <C>             <C>
Outstanding - Beginning
  of year. . . . . . . . . . . . . . .         $ 4.45-$25.63      2,308,823     2,388,970       2,327,410

  Granted. . . . . . . . . . . . . . .         $13.25-$17.44        263,200       144,700         257,000

  Exercised (a). . . . . . . . . . . .         $12.50-$17.00        (27,825)      (32,347)       (115,270)

  Canceled or expired. . . . . . . . .         $12.50-$25.63        (29,600)     (192,500)        (80,170)
                                                                  ---------     ---------       ---------
Outstanding - End of year. . . . . . .         $ 4.45-$23.88      2,514,598     2,308,823       2,388,970
                                                                  =========     =========       =========
Exercisable. . . . . . . . . . . . . .         $ 4.45-$23.88      1,957,637     1,838,175       1,737,127
                                                                  =========     =========       =========
<FN>
(a)  Price ranges for options exercised in 1994 were $4.45 to $12.50 and in 1993 were $12.50 to $21.00 per
     share.
</FN>
</TABLE>

The current stock option plan was amended in February 1994 to include
provisions for granting restricted stock.  At December 31, 1995, a total of
128,456 shares of performance-based restricted stock had been issued to
certain officers and were outstanding.  Performance criteria for lifting the
restrictions is related to three-year total shareholder return compared with
the weighted average of a peer group of companies.  In addition, a total of
11,501 shares of non-performance based restricted stock were issued in May
1995  to certain non-employee directors and were outstanding at December 31,
1995.

                                A-28
<PAGE>
<PAGE>
6.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The Corporation's operations involve managing market risks related to changes
in interest rates and commodity prices.  Derivative financial instruments,
specifically swaps, futures, options and other contracts, are used to reduce
and manage those risks.

Interest-Rate Swaps - In November 1995, EEX entered into an interest-rate swap
on a notional amount of $150 million to fix the interest rate associated with
the mandatorily redeemable preferred securities of subsidiary.  The notional
amount declines on a schedule that parallels the estimated redemption of the
securities and terminates in July 2000.  Under the swap agreement, EEX is to
receive interest on the outstanding notional amount at a rate (5.94% in effect
at December 31, 1995) based on LIBOR, reset quarterly, and is to pay a fixed
rate of 5.8%.  The net effect of the swap fixes the rate on the preferred
dividends at 6.49%.

In December 1995, the Corporation entered into an interest-rate swap with a
bank on a notional amount of $150 million to fix the interest on $150 million
of the $210 million floating rate obligations of the Garden Banks lease at a
fixed cost of 5.71%.  The swap has a staggered maturity out to seven years
with an average life of approximately five years.  The cost of the Garden
Banks lease is based on the three month LIBOR rate (which was 5.81% at the
date of the agreement in December 1995).

The Corporation is exposed to market risk under these swap arrangements due
to the possibility of exchanging a lower interest rate for a higher interest
rate.  The counterparties are major financial institutions, and the risk of
incurring losses related to credit risk is considered by the Corporation to
be remote.

Hedging Activities - The Corporation, through EEX, enters into swaps, futures
and other derivative contracts to hedge the price risks associated with a
portion of anticipated future gas and oil production.  Under these agreements,
payments are received or made based on the differential between a fixed and
a variable product price.  These agreements are settled in cash at or prior
to expiration or exchanged for physical delivery contracts.  The Corporation
does not obtain collateral to support the agreements but monitors the
financial viability of counterparties and believes its credit risk is minimal
on these transactions.  In the event of nonperformance by counterparties, the
Corporation would be exposed to price risk.  The Corporation has some risk of
accounting loss since the price received for the product at the actual
physical delivery point may differ from the prevailing price at the delivery
point required for settlement of the hedging transaction.

In late December 1995, there was a temporary cessation to the historical
correlation of natural-gas prices in the physical market that serves as the
delivery point for NYMEX future contracts and the prices in certain other
physical markets where EEX sells a substantial portion of its natural-gas
production.  As a result, EEX's NYMEX futures contracts for the first quarter
of 1996 no longer served as effective hedges for the portion of production
that would be sold in market locations other than those to which the NYMEX

                                A-29
<PAGE>
<PAGE>
contracts were tied.  In late December and early January, EEX closed
substantially all of its first quarter 1996 NYMEX futures contracts and, as
a result, recognized a loss of $6.0 million in 1995.  For the full year 1995,
EEX recognized a net gain of $.1 million on hedging activities related to the
sale of its gas and oil production.

At December 31, 1995, EEX had outstanding swaps, collars and futures
agreements that were entered into as hedges extending through December 31,
1996 to exchange payments on 39 Bcf of natural gas and 655 MBbls of oil.   The
weighted average strike price and market price per Mcf of natural gas was
$2.01 and $2.10, respectively, and the weighted average strike price and
market price per barrel of oil was $18.43 and $19.03, respectively. At
December 31, 1995, after giving effect to the $6.0 million mark-to-market loss
mentioned above, there were $1.3 million of net unrealized and unrecognized
hedging losses based on the difference between the strike price and the NYMEX
futures price for the applicable trading month.  In addition, there were $2.4
million of realized losses on hedging activities which were deferred and will
be applied as a reduction in revenues in the month of physical sale of
production.

Natural Gas Marketing Activities - The Corporation, through EES, is a marketer
of natural gas and natural-gas services.  As part of these business
activities, EES enters into a variety of transactions, including forward
contracts principally involving physical delivery of natural gas and
derivative financial instruments, including swaps, options, futures and other
contractual arrangements.  The derivative transactions are concentrated with
established energy companies and major financial institutions.

EES's marketing activities involve price commitments into the future and,
therefore, give rise to market risk, which represents the potential loss that
can be caused by a change in the market value of a particular commitment.
Net open portfolio positions often result from the origination of new
transactions or in response to changing market conditions.  The Corporation
closely monitors and manages its exposure to market risk.

Credit risk relates to the risk of loss that the Corporation would incur as
a result of nonperformance by counterparties pursuant to the terms of their
contractual obligations.  The Corporation maintains credit policies with
regard to its counterparties that management believes significantly minimize
overall credit risk.  The Corporation does not obtain collateral to support
the agreements but monitors the financial viability of counterparties and
believes its credit risk is minimal on these transactions.

EES enters into contracts to purchase and sell natural gas for physical
delivery in the future.  At December 31, 1995, EES had net commitments to
purchase 33 trillion Btu's (about 32 Bcf) of natural gas through the year 2000
with offsetting net financial positions to sell 27 trillion Btu's (about 26
Bcf), including commitments to purchase 41 trillion Btu's (about 40 Bcf) from
EEX and financial positions to sell the same quantity. There was a net
unrealized and unrecognized gain of $2.7 million at December 31, 1995 on these
contracts.  At December 31, 1994, EES had a net commitment to purchase natural
gas for which a $4 million charge was recorded to reflect lower year-end
market prices.

                                A-30
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Fair Value of Financial Instruments
  at December 31:                                                        1995                      1994
                                                                 ---------------------     ---------------------
                                                                 Carrying    Estimated     Carrying    Estimated
                                                                or Notional     Fair      or Notional     Fair
                                                                   Amount       Value        Amount       Value
                                                                 ---------    --------    ----------   ---------
<S>                                                              <C>          <C>          <C>          <C>
Senior long-term debt (a). . . . . . . . . . . . .               $887,079     $908,425     $727,597     $697,378
Convertible debentures (b) . . . . . . . . . . . .                 90,750       88,027       90,750       77,138

Off-balance sheet assets (liabilities)
  Recoverable gas-purchase contracts (c) . . . . .                  5,769        5,872       30,264       29,726
  Receivables sold with limited
    recourse (d) . . . . . . . . . . . . . . . . .                100,000      100,000      132,723      132,723
  Interest-rate swaps (e). . . . . . . . . . . . .                              (2,664)
  EEX gas and oil swaps (e). . . . . . . . . . . .                              (1,324)                    4,085
  EES derivatives (f). . . . . . . . . . . . . . .                               2,695                      (160)
  Financial guarantees (e) . . . . . . . . . . . .                            (119,095)                 (111,435)

<FN>
Estimated fair value:  (a) variable-rate debt - approximates carrying amount, exchange traded debt - quoted
market prices, and other debt - discounted value using rates for debt with similar characteristics; (b)
quoted market prices; (c) discounted cash flows; (d) approximates carrying or notional amount; (e) based
either on quotes or the cost to terminate or otherwise settle the agreements; (f) based on mark-to-market
valuations.
</FN>
</TABLE>
The fair value of other financial instruments, consisting primarily of cash
and equivalents, accounts receivable, investments, commercial paper and other
short-term borrowings, accounts payable, accrued interest and mandatorily
redeemable preferred securities of subsidiary, approximated carrying value.
The estimated fair value of senior long-term debt does not reflect prepayment
penalties, which would be incurred upon early extinguishment.

7.  COMMITMENTS AND CONTINGENT LIABILITIES

Legal Proceedings - A lawsuit was filed on February 24, 1987, in the 112th
Judicial District of Sutton County, Texas, against subsidiaries and affiliates
of the Corporation and its utility division.  The plaintiffs have claimed that
defendants failed to make certain production and minimum-purchase payments
under a gas-purchase contract.  The plaintiffs have alleged a conspiracy to
violate purchase obligations, improper accounting of amounts due, fraud,
misrepresentation, duress, failure to properly market gas and failure to act
in good faith.  Plaintiffs seek actual damages in excess of $5 million and
punitive damages in an amount equal to 0.5% of the consolidated gross revenues
of the Corporation for the years 1982-1986 (approximately $85 million),
interest, costs and attorneys' fees.

On September 20, 1994, the first of 21 asbestos related lawsuits was filed
against former subsidiaries of the Corporation and numerous other unrelated
defendants in the District Court of Wyandotte County, Kansas.  There are
currently 280 plaintiffs who claim to have been exposed to asbestos and
asbestos  related  products  at  their places of employment since 1935.  The
plaintiffs are claiming damages of $123 million for physical and psychological
injuries under theories of negligence, strict liability and breach of
warranty.

                                A-31
<PAGE>
<PAGE>
On October 30, 1995, a lawsuit was filed in the Supreme Court of Western
Australia by Woodside Petroleum Ltd. and its joint venture partners against
the Corporation, a former subsidiary of the Corporation, and others.
Plaintiffs seek damages of approximately $18 million from the Corporation
based on an indemnity arrangement and approximately $208 million from the
other defendants for alleged breaches of contract and breaches of a trade
practice act, all in connection with the construction of an offshore gas and
condensate drilling production platform.  The Corporation has agreed to
indemnify  the  current  owner  of  the  former  subsidiary pursuant to the
provisions in the prior sales agreement.  The Corporation is reviewing the
relevant documents and facts in order to determine the extent, if any, of its
potential liability in the lawsuit.

Management of the Corporation believes it has meritorious defenses to the
claims made in these and other actions brought in the ordinary course of
business.  In the opinion of management, the Corporation will incur no
liability from these and all other pending claims and suits that is material
for financial reporting purposes.

Environmental Matters - The Corporation is subject to federal, state and local
environmental laws and regulations that regulate the discharge of materials
into the environment.  Environmental expenditures are expensed or capitalized
depending on their future economic benefit. The level of future expenditures
for environmental matters, including costs of obtaining operating permits,
equipment monitoring and modifications under the Clean Air Act and cleanup
obligations, cannot be fully ascertained until the regulations that implement
the applicable laws have been approved and adopted.  It is management's
opinion that all such costs, when finally determined, will not have a material
adverse effect on the consolidated financial position or results of operations
of the Corporation.

Commitments - Future minimum commitments are as follows (in millions):
<TABLE>
<CAPTION>

                                                  1996   1997   1998   1999   2000   Thereafter
                                                 -----  -----  -----  -----  -----   ----------
<S>                                              <C>    <C>    <C>    <C>    <C>        <C>
Operating leases (a) . . . . . . . . . . . .     $25.2  $14.4  $ 9.8  $ 7.3  $ 6.7      $67.3
Capital leases (b) . . . . . . . . . . . . .       4.0    3.9    3.7    1.8   23.3          -
Gas-purchase contracts . . . . . . . . . . .     120.0  113.0   89.0   38.0    9.0        2.0
<FN>
(a) Excludes $168 million of guaranteed estimated residual value to be paid in 1998 if the lease terminates.
(b) Includes a total of $6.3 million representing interest.
</FN>
</TABLE>
Lease Commitments - In 1992, the Corporation entered into operating lease
arrangements to provide financing for its portion of the offshore platforms
and related facilities for the Mississippi Canyon Block 441 (37.5% owned) and
Garden Banks Block 388 (60% owned) projects.  The leases contain fixed-priced
purchase options and, if terminated, require a guaranteed residual payment.

The lease for the Mississippi Canyon Block 441 project was modified in the
second quarter of 1994 with terms that resulted in capital lease accounting
treatment and a noncash investing and financing transaction of $34 million.
The balance of the lease obligation is $30.4 million at December 31, 1995; the
noncurrent portion of the lease obligation of $28.4 million at year-end 1995
is included in other noncurrent liabilities.

                                A-32
<PAGE>
<PAGE>
In the third quarter of 1995, a Mobil Corporation (Mobil) affiliate acquired
a 40% working interest in EEX's Garden Banks Block 388 project; accordingly,
ENSERCH was relieved of operating lease obligations of approximately $140
million, as well as 40% of the capital expenditures required to complete the
project.  EEX now owns a 60% working interest in the project and remains the
operator.

Under the Garden Banks lease arrangement, the lessor funded EEX's $210 million
(60%) share of construction cost of the facilities.  The facilities have been
leased for an initial period extending through March 31, 1998.  The lease may
be extended for up to three successive two-year periods on such terms as the
Corporation and lessor may agree.  The Corporation has the option to purchase
the facilities throughout the lease period and has guaranteed an estimated
residual value for the facilities of approximately $168 million should the
lease terminate.  Lease payments were deferred prior to commencement of
production in the third quarter of 1995.  Amortization of the deferred lease
payments began at that time.

The Corporation had a number of other noncancelable long-term operating leases
at December 31, 1995, principally for office space and machinery and
equipment.  Rental expenses incurred under all operating leases aggregated
$13.1 million in 1995, $8.4 million in 1994 and $11.0 million in 1993.  Rental
income received for subleased office space was $3.4 million in 1995, $3.6
million in 1994 and $3.4 million in 1993.  Future minimum rental income to be
received for subleased office space is $6.9 million over the next five years.

Gas-Purchase Contracts - Lone Star Gas Company buys gas under long-term,
intrastate contracts in order to assure reliable supply to its customers.
Many of these contracts require minimum purchases of gas.  LSG has made
accruals for payments that may be required for settlement of gas-purchase
contract claims asserted or that are probable of assertion.  LSG continually
evaluates its position relative to asserted and unasserted claims, above-
market prices or future commitments.  Management believes that LSG has not
incurred losses for which reserves should be provided at December 31, 1995.
Based on estimated gas demand, which assumes normal weather conditions,
requisite gas purchases are expected to substantially satisfy purchase
obligations for the year 1996 and thereafter.

Sales of Receivables - The Corporation has sold $100 million of receivables
under a limited recourse agreement that extends to October 31, 1996.
Additional receivables are continually sold to replace those collected.  The
agreement is expected to be extended.  The uncollected balance of sold
receivables of discontinued operations was repurchased during 1995.  The
uncollected balances of receivables sold were $100 million at year-end 1995
and $133 million at year-end 1994.

Guarantees - The Corporation and/or its subsidiaries are the guarantor on
various commitments and obligations of others aggregating some $119 million
at December 31, 1995.  The Corporation is exposed to loss in the event of
nonperformance by other parties.  However, the Corporation does not anticipate
nonperformance by the counterparties.

                                A-33
<PAGE>
<PAGE>
Concentrations of Credit Risk - Lone Star Gas operations have trade
receivables from a few large industrial customers in North Central Texas
arising from the sale of natural gas.  A change in economic conditions may
affect the ability of customers to meet their contractual obligations.  At
December 31, 1995 and 1994, the allowance for possible losses deducted from
accounts receivable was $5,174 and $5,264, respectively.  The Corporation
believes that its provision for possible losses on uncollectible accounts
receivable is adequate for its credit loss exposure.

8.  EMPLOYEE BENEFIT PLANS

Pension Plan - A defined benefit pension plan provides retirement income
benefits for substantially all employees.  Accrued retirement costs are funded
to the extent such amounts are deductible for federal income tax purposes.
Plan assets include equity and fixed-income securities and cash.  Benefits are
based on years of credited service and average compensation.
<TABLE>
<CAPTION>

Components of Net Pension Expense                                   1995             1994            1993
  (in millions):                                                  ------            -----           -----
<S>                                                               <C>               <C>             <C>
Service cost - benefits earned during the period . . . .          $  3.8            $ 7.5           $12.5
Interest cost on projected benefit obligation. . . . . .            23.5             22.6            19.5
Actual (return) loss on assets . . . . . . . . . . . . .           (46.8)             3.8           (28.0)
Net amortization and deferral. . . . . . . . . . . . . .            24.0            (27.4)            3.9
                                                                  ------            -----           -----
Net periodic pension expense . . . . . . . . . . . . . .          $  4.5            $ 6.5           $ 7.9
                                                                  ======            =====           =====
Valuation Assumptions:

Discount rate. . . . . . . . . . . . . . . . . . . . . .            7.65%            9.00%           7.25%
Rate of increase in compensation levels. . . . . . . . .            4.00%            4.00%           4.00%
Expected long-term rate of return on assets. . . . . . .            9.50%            9.50%           9.50%

Amounts Recognized (in millions):

Actuarial present value of pension benefit obligation:
  Vested benefit obligation. . . . . . . . . . . . . . .         $(297.0)         $(238.0)
                                                                 =======          =======
  Accumulated benefit obligation . . . . . . . . . . . .         $(299.3)         $(250.2)
                                                                 =======          =======
  Projected pension benefit obligation . . . . . . . . .         $(327.9)         $(272.1)
Plan assets at fair value. . . . . . . . . . . . . . . .           263.1            232.2
                                                                 -------          -------
Projected benefit obligation in excess of plan assets. .           (64.8)           (39.9)
Unrecognized net asset at transition . . . . . . . . . .            (6.0)            (8.0)
Unrecognized prior service cost (credit) . . . . . . . .            (3.5)            (2.2)
Unrecognized net actuarial loss (gain) . . . . . . . . .            16.9             (3.7)
                                                                 -------          -------
Accrued pension cost . . . . . . . . . . . . . . . . . .         $ (57.4)         $ (53.8)
                                                                 =======          =======
</TABLE>
ENSERCH retained the pension obligations to former engineering and
construction employees.  No further benefits will accrue for the former
employees.  Plan curtailment gains of $2.2 million in 1994 and $6.9 million
in 1993 were recognized in discontinued operations.

                                A-34
<PAGE>
<PAGE>
Investment Plan - A voluntary contributory investment plan is available to
substantially all employees.  The Corporation matches a portion of employees'
contributions with ENSERCH common stock or, at the employee's option, EEX
common stock.  Costs under the plans were $1.8 million, $1.9 million and
$3.5 million in 1995, 1994, and 1993, respectively.

Postretirement Benefits Other than Pensions - Some retirees and their
dependents receive postretirement medical benefits that vary in level based
on their years of service and retirement date.  Employees hired after July 1,
1989 are not eligible for medical benefits when they retire.  Obligations are
not prefunded.
<TABLE>
<CAPTION>

Components of Net Periodic Postretirement Benefit
  Cost (in millions):                                               1995          1994          1993
                                                                  -------       -------        -------
<S>                                                                <C>          <C>            <C>
Service cost - benefits earned during the period . . . . . . .     $   .2       $    .4        $    .4
Interest cost on projected benefit obligation. . . . . . . . .        6.0           5.5            5.6
Net amortization and deferral. . . . . . . . . . . . . . . . .        3.6           4.3            4.0
                                                                   ------       -------        -------
Net periodic postretirement benefit cost . . . . . . . . . . .     $  9.8       $  10.2        $  10.0
                                                                   ======       =======        =======

Valuation Assumptions:

Discount rate. . . . . . . . . . . . . . . . . . . . . . . . .       7.65%         9.00%          7.25%
Medical cost trend rate. . . . . . . . . . . . . . . . . . . .       7.00%        12.00%         12.00%

Amounts Recognized (in millions):

Accumulated postretirement benefit obligations:
  Retirees and dependents. . . . . . . . . . . . . . . . . . .     $(68.3)      $ (75.2)
  Fully eligible active plan participants. . . . . . . . . . .        (.3)         (1.0)
  Other active plan participants . . . . . . . . . . . . . . .       (6.9)         (6.7)
                                                                   ------       -------
Accumulated postretirement benefit obligation. . . . . . . .        (75.5)        (82.9)
Unrecognized obligation at transition. . . . . . . . . . . . .       58.1          62.1
Unrecognized net actuarial loss. . . . . . . . . . . . . . . .       10.0          15.1
                                                                   ------       -------
Accrued postretirement benefit cost. . . . . . . . . . . . . .     $ (7.4)      $  (5.7)
                                                                   ======       =======
</TABLE>

The assumed health care cost trend rate is 7.0% for 1995, declining gradually
to 4.5% after 1999, and remaining at that level thereafter.  If the health
care cost trend rate were increased by 1%, the accumulated postretirement
benefit obligation as of December 31, 1995 and the net periodic postretirement
benefit cost for 1995 would be increased by $4.6 million and $.4 million,
respectively.

                                A-35
<PAGE>
<PAGE>
9.  INCOME TAXES
<TABLE>
<CAPTION>
Provision (Benefit) for Income Taxes
  on Continuing Operations:                                  1995              1994                1993
                                                            -------          --------             -------
<S>                                                         <C>              <C>                  <C>
Current
  Federal. . . . . . . . . . . . . . . . . . . . .          $ 6,230          $(10,196)            $ 7,464
  State. . . . . . . . . . . . . . . . . . . . . .              321               560                 463
  Foreign. . . . . . . . . . . . . . . . . . . . .               50                50                (444)
                                                            -------          --------             -------
    Total. . . . . . . . . . . . . . . . . . . . .            6,601            (9,586)              7,483
                                                            -------          --------             -------
Deferred
  Federal. . . . . . . . . . . . . . . . . . . . .           (5,680)          (59,151)             (1,302)
  State. . . . . . . . . . . . . . . . . . . . . .                                                    455
                                                           --------          --------             -------
    Total. . . . . . . . . . . . . . . . . . . . .           (5,680)          (59,151)               (847)
                                                           --------          --------             -------
      Total. . . . . . . . . . . . . . . . . . . .         $    921          $(68,737)            $ 6,636
                                                           ========          ========             =======
</TABLE>
<TABLE>
<CAPTION>
Reconciliation of Income Taxes (Benefit) Computed at the Federal Statutory
  Rate to Provision for Income Taxes (Benefit) of Continuing Operations:

                                                              1995              1994                1993
Income (loss) from continuing                               -------          --------            --------
  operations before income taxes:
  <S>                                                       <C>              <C>                 <C>
  Domestic . . . . . . . . . . . . . . . . . . . .          $17,230          $ 16,582            $  9,102
  Foreign. . . . . . . . . . . . . . . . . . . . .           (3,858)           (3,294)            (18,469)
                                                            -------          --------            --------
    Total. . . . . . . . . . . . . . . . . . . . .          $13,372          $ 13,288            $ (9,367)
                                                            =======          ========            ========
Income taxes (benefit) computed at
    the federal statutory rate of 35%. . . . . . .          $ 4,680          $  4,651            $ (3,278)
Impact of 1% increase in federal statutory rate. .                                                 10,810
Change in tax status . . . . . . . . . . . . . . .                            (70,000)
State and foreign taxes. . . . . . . . . . . . . .              242               397                 467
Reduction of prior year tax liabilities. . . . . .           (3,590)           (3,734)                (67)
Nondeductible meals and entertainment. . . . . . .              427               360                 126
Amortization of property basis difference
  from EEX stock sale. . . . . . . . . . . . . . .             (454)
Percentage depletion . . . . . . . . . . . . . . .             (324)              (22)                (43)
Tax benefit of dividends to ESOP . . . . . . . . .                               (256)               (316)
Basis difference in investment sold. . . . . . . .                                                   (509)
Other - net. . . . . . . . . . . . . . . . . . . .              (60)             (133)               (554)
                                                           --------          --------            --------

    Provision for Income Taxes (Benefit) . . . . .         $    921          $(68,737)           $  6,636
                                                           ========          ========            ========
</TABLE>

At the completion of the conversion of EP and EPPL to corporate form in 1994,
the tax basis of certain properties of ENSERCH and subsidiary companies
receiving EEX stock in the conversion exceeded the financial basis of such
properties.  Also, the financial basis of ENSERCH and subsidiary companies in
EEX exceeds their tax basis in the EEX stock.  ENSERCH expects to ultimately
recover the excess financial basis tax free.  As a result of the conversion
and related change in tax status, deferred income taxes applicable to the
difference between the financial and tax basis of ENSERCH and subsidiary
companies' investment in the partnerships were reduced by $70 million in 1994.

                                A-36
<PAGE>
<PAGE>
Deferred income taxes provided by the liability method for significant
temporary differences based on tax laws and statutory rates in effect at the
December 31, 1995 and 1994 balance sheet dates are as follows:
<TABLE>
<CAPTION>
                                               1995                                   1994
                                    --------------------------------     -------------------------------
                                    Total      Current    Noncurrent     Total     Current    Noncurrent
                                    -------   ---------   ----------     -------   --------   ----------
<S>                                 <C>          <C>        <C>         <C>         <C>          <C>
Deferred Tax Assets:
Net operating-loss and other tax-
  credit carryforwards . . . . . .  $103,915     $          $103,915    $ 98,582    $   891      $ 97,691
Retirement and other employee
  benefit obligations. . . . . . .    27,811       3,078      24,733      24,139      4,342        19,797
Accruals and allowances. . . . . .    27,755      15,452      12,303      36,857     23,055        13,802
Losses of controlled foreign
  corporations . . . . . . . . . .     9,848                   9,848       8,790                    8,790
All other. . . . . . . . . . . . .    14,212       4,356       9,856      13,646      4,586         9,060
                                    --------     -------    --------    --------    -------       -------
  Total. . . . . . . . . . . . . .   183,541      22,886     160,655     182,014     32,874       149,140
                                    --------     -------    --------    --------    -------       -------
Deferred Tax Liabilities:
Exploration and intangible
  development costs. . . . . . . . . 209,443                 209,443     218,289                  218,289
Property-related
  differences. . . . . . . . . . . . 166,419                 166,419     151,452                  151,452
Deferred gas-purchase contract
  settlements. . . . . . . . . .       1,553       1,553                  10,145      8,398         1,747
All other. . . . . . . . . . . . . .  61,877           8      61,869      57,703                   57,703
                                    --------    --------    --------    --------   --------       -------
  Total. . . . . . . . . . . . . . . 439,292       1,561     437,731     437,589      8,398       429,191
                                    --------    --------    --------    --------   --------       -------
Net Deferred Tax Liability (Asset)  $255,751    $(21,325)(a)$277,076    $255,575   $(24,476)(a)  $280,051
                                    ========    ========    ========    ========   ========      ========
<FN>
(a) Included in other current assets in the balance sheet.
</FN>
</TABLE>
At December 31, 1995, domestic net operating-loss carryforwards total
$222 million, which begin to expire in 2003, and tax-credit carryforwards
total $26 million, which begin to expire in 1999.  The tax benefits of these
carryforwards of $104 million, as shown above, are available to reduce future
income-tax payments.
<TABLE>
<CAPTION>
Cash Payments (Refunds) of Income Taxes:                      1995              1994              1993
                                                           --------          --------           -------
<S>                                                        <C>               <C>                <C>
Federal:
  Current year, including alternative
    minimum tax. . . . . . . . . . . . . . . . . .         $  8,363          $ 10,650           $13,857
  Prior years. . . . . . . . . . . . . . . . . . .          (10,413)          (12,148)            2,000
                                                           --------          --------           -------
    Total. . . . . . . . . . . . . . . . . . . . .           (2,050)           (1,498)           15,857
State. . . . . . . . . . . . . . . . . . . . . . .           (3,609)            6,743             4,193
Foreign. . . . . . . . . . . . . . . . . . . . . .                                                  850
                                                           --------          --------           -------
    Total. . . . . . . . . . . . . . . . . . . . .         $ (5,659)         $  5,245           $20,900
                                                           ========          ========           =======
</TABLE>


                                A-37
<PAGE>
<PAGE>

10.  DISCONTINUED OPERATIONS

In October 1994, the Corporation sold Enserch Environmental Corporation, which
conducted the former environmental businesses of Ebasco Services Incorporated
(Ebasco), for $98 million.  The principal operating assets of Ebasco were sold
in December 1993 for net proceeds of $191 million.  Also in December 1993,
Dorsch Consult was sold for $9.3 million, including the assumption of debt.
Discontinued operations are summarized as follows:
<TABLE>
<CAPTION>

Operating Information:                                           1995             1994             1993
                                                                -------        ---------       ----------
<S>                                                            <C>             <C>             <C>
Revenues . . . . . . . . . . . . . . . . . . . . . . . .                       $  72,081       $1,416,450
Cost and expenses. . . . . . . . . . . . . . . . . . . .                          68,246        1,391,002
                                                                               ---------       ----------
Operating income . . . . . . . . . . . . . . . . . . . .                           3,835           25,448
Other income (expense) - net . . . . . . . . . . . . . .                                             (583)
Interest expense . . . . . . . . . . . . . . . . . . . .                          (1,241)         (12,488)
Income taxes . . . . . . . . . . . . . . . . . . . . . .                          (1,225)          (5,373)
                                                                               ---------       ----------
Income from operations . . . . . . . . . . . . . . . . .                           1,369            7,004
Gain on sale, net of income-tax provision
  of $15,750 in 1994 and benefit of $6,725
  in 1993. . . . . . . . . . . . . . . . . . . . . . . .                          29,250           68,414
Provision for additional costs and
  expenses for the windup of discontinued
  businesses, net of tax benefit of $7,523 . . . . . . .                          (9,977)
                                                                               ---------       ----------
    Total  . . . . . . . . . . . . . . . . . . . . . . .                       $  20,642       $   75,418
                                                                               =========       ==========
Cash Flow Information:
Net cash flows from (used for)
  Operating activities . . . . . . . . . . . . . . . . .       $(28,102)       $(107,487)      $   93,934
  Proceeds from sales of assets. . . . . . . . . . . . .                          97,749          198,113
  Investing activities . . . . . . . . . . . . . . . . .                           8,796           26,361
                                                               --------        ---------       ----------
    Net cash flows from (used for) discontinued
      operations . . . . . . . . . . . . . . . . . . . .       $(28,102)       $    (942)      $  318,408
                                                               ========        =========       ==========
</TABLE>

The tax effect of the 1993 gain on sale differs from tax at the statutory rate
because of permanent differences in financial and tax basis of the assets
sold.  The determination of the gain on the sale of the principal operating
assets of Ebasco in 1993 involved significant estimates, including the final
purchase price, realization of the estimated value of retained assets and
related income-tax matters.  In 1994, a loss provision of $17.5 million pretax
($10.0 million after-tax) was recorded in recognition that costs and expenses
incurred for the windup of discontinued businesses would be greater than
previously estimated.

At December 31, 1995, discontinued businesses had assets of $74 million,
consisting principally of retained claims and accounts receivable, and current
and other liabilities and reserves of $47 million.  The Corporation has filed
suit against certain parties to recover amounts outstanding.  Management
expects that substantially all disputes will be resolved by year-end 1997 and
that adequate provision for uncollectible claims and accounts receivable,
income-tax matters and expenses for windup of discontinued operations has been
made.

                                A-38
<PAGE>
<PAGE>
11.   SUPPLEMENTARY GAS AND OIL INFORMATION

Gas and Oil Producing Activities - The following tables set forth information
relating to gas and oil producing activities.  Reserve data for natural gas
liquids attributable to leasehold interests owned by the Corporation are
included in oil and condensate.
<TABLE>
<CAPTION>

Capitalized Costs (in millions):                                       1995             1994
                                                                     --------         --------
<S>                                                                  <C>              <C>
Proved gas and oil properties. . . . . . . . . . . . .               $2,362.1         $1,946.5
Unproved gas and oil properties. . . . . . . . . . . .                  199.3            108.2
                                                                     --------         --------
  Total. . . . . . . . . . . . . . . . . . . . . . . .               $2,561.4         $2,054.7
                                                                     ========         ========
Accumulated depreciation and amortization. . . . . . .               $  933.4         $  836.3
                                                                     ========         ========
</TABLE>
A net credit of $59 million arising from the sale of EEX common stock in
September 1995 was treated as a reduction of the carrying value of gas and oil
properties (see Note 2).
<TABLE>
<CAPTION>

Costs Incurred (in millions):                           1995                   1994                   1993
                                                --------------------     --------------------     ------------------
                                                                 Non-                    Non-                  Non-
                                                    U.S.         U.S.        U.S.        U.S.       U.S.       U.S.
                                                --------    --------     --------   ---------     --------   -------
<S>                                               <C>          <C>         <C>         <C>         <C>        <C>
Property acquisition costs:
  Proved . . . . . . . . . . .                    $356.3       $           $  1.6      $           $  8.3     $
  Unproved . . . . . . . . . .                     121.6                     20.6                    12.6         .8
Exploration costs. . . . . . .                      59.5         9.0         58.7         3.3        36.8        4.9
Development costs. . . . . . .                      46.2                     84.2                    63.0
                                                  ------      ------       ------      ------      ------     ------
  Total. . . . . . . . . . . .                    $583.6      $  9.0       $165.1      $  3.3      $120.7     $  5.7
                                                  ======      ======       ======      ======      ======     ======
Amortization
  (Per MMBtu)(a) . . . . . . .                    $ 1.01                   $ 1.04                  $  .98
<FN>
(a) Amortization expense per unit of production converted to a common unit of measure, millions of British
    thermal units (MMBtu); on a per thousand cubic feet of gas equivalent (Mcfe) basis, the amounts are: $1.03,
    $1.06 and $1.01.
<FN>
</TABLE>
<TABLE>
<CAPTION>
Costs Excluded from the Amortizable Base as of December 31, 1995 (in
  millions):

                                                                                            Total at
                                                                                Prior      December 31,
Year Incurred                          1995           1994         1993         Years         1995
                                       ----           ----         ----         -----      ------------
<S>                                   <C>            <C>          <C>           <C>          <C>
Property acquisition costs . .        $117.9         $18.8        $ 9.2         $ 1.9        $147.8
Exploration costs. . . . . . .          20.2          14.2          3.9           1.1          39.4
Interest capitalized . . . . .           5.3           3.0          2.1           1.7          12.1
                                      ------         -----        -----         -----        ------
    Total. . . . . . . . . . .        $143.4         $36.0        $15.2         $ 4.7        $199.3
                                      ======         =====        =====         =====        ======
</TABLE>
                                A-39
<PAGE>
<PAGE>
Approximately 20% of the excluded costs relates to offshore activities in the
Gulf of Mexico, about 76% is domestic onshore exploration activities and the
remainder is non-U.S.  The anticipated timing of the inclusion of these costs
in the amortization computation will be determined by the rate at which
exploratory and development activities continue, which are expected to be
accomplished within ten years.

The following information is required and defined by the Financial Accounting
Standards Board.  The disclosure does not represent the results of operations
based on historical financial statements.  In addition to requiring different
determinations of revenues and costs, the disclosure excludes interest expense
and corporate overhead.

<TABLE>
<CAPTION>
                                           1995                   1994                1993
                                     -----------------     ----------------    -----------------
Results of Operations                          Non-                    Non-                Non-
  (in millions):                        U.S.   U.S.           U.S.     U.S.      U.S.      U.S.
                                     -------- -------      -------   -------   --------  -------
 <S>                                   <C>      <C>          <C>       <C>       <C>       <C>
 Revenues:
   Affiliated. . . . . . . .           $ 86.7   $            $110.0    $         $110.0    $
   Nonaffiliated . . . . . .            131.9                  63.5                81.0
 Less:
   Production costs (a). . .             67.2                  44.0                45.9
   Exploration costs (b) . .              9.6      2.3          8.4      1.0        7.6      1.6
   Depreciation and
     amortization (c). . . .            116.4       .9         85.6                86.0     13.3
   Income-tax effects. . . .              8.6     (1.1)        12.4      (.3)      18.0     (5.2)
                                       ------   ------       ------    -----     ------    -----
    Net producing
      activities . . . . . . .         $ 16.8   $ (2.1)      $ 23.1    $ (.7)    $ 33.5    $(9.7)
                                       ======   ======       ======    =====     ======    =====
<FN>
(a) Includes severance, ad valorem and production taxes.
(b) Includes internal costs that cannot be directly identified with acquisition, exploration or development
    activities.
(c) Amounts for 1995 and 1993 include write-downs of non-U.S. exploratory projects of $.9 million and $13.3
    million, respectively.  Amount for 1994 excludes a $7.6 million gain from the sale of an inactive offshore
    pipeline and facilities, which were not related to gas and oil producing activities.
</FN>
</TABLE>
                                A-40
<PAGE>
<PAGE>
Gas and Oil Reserves (Unaudited) - The following table of estimated proved and
proved developed reserves of gas and oil has been prepared utilizing estimates
of year-end reserve quantities provided by DeGolyer and MacNaughton,
independent petroleum consultants.  Reserve estimates are inherently imprecise
and estimates of new discoveries are more imprecise than those of producing
gas and oil properties.  Accordingly, the reserve estimates are expected to
change as additional performance data become available.

<TABLE>
<CAPTION>
U. S. Reserves:                                   Gas (MMcf)                       Oil (MBbls)(a)
                                       ---------------------------------    ------------------------
                                         1995         1994         1993       1995     1994     1993
                                       ----------  ----------  ---------    -------- -------- -------
<S>                                     <C>         <C>         <C>          <C>      <C>      <C>
At January 1 . . . . . . . . . . . .    1,041,736   1,086,482   1,101,426    46,486   39,349   39,231
Changes in reserves
  Revisions of previous estimates. .       26,802     (25,106)     20,196     2,312     (499)   1,344
  Extensions, discoveries
     and additions . . . . . . . . .       62,249      47,580      34,549    21,466    9,877    1,292
  Purchase of minerals in place. . .      336,668         787       4,379    11,417       14        3
  Sales of minerals in place . . . .      (14,497)       (894)     (4,042)  (11,274)     (28)     (40)
  Production . . . . . . . . . . . .      (90,195)    (67,113)    (70,026)   (3,870)  (2,227)  (2,481)
                                        ---------   ---------   ---------   -------  -------  -------
At December 31 . . . . . . . . . . .    1,362,763   1,041,736   1,086,482    66,537   46,486   39,349
                                        =========   =========   =========   =======  =======  =======

Proved Developed Reserves
  At January 1 . . . . . . . . . . .      698,643     735,093     676,851    14,437   15,380   14,844
  At December 31 . . . . . . . . . .      937,372     698,643     735,093    30,110   14,437   15,380
<FN>
(a) Includes condensate and natural gas liquids attributable to leasehold interests of 3,593 MBbls for 1995,
    911 MBbls for 1994 and 1,117 MBbls for 1993.
</FN>
</TABLE>
<TABLE>
<CAPTION>

                                                Oil (MBbls)
                                          --------------------
Non-U.S. Reserves:                          1995         1994
                                          -------     --------
<S>                                         <C>         <C>
At January 1 . . . . . . . . . . . .        4,105           0
  Extensions, discoveries
     and additions . . . . . . . . .          858       4,105
                                           ------      ------
At December 31 . . . . . . . . . . .        4,963       4,105
                                           ======      ======
Proved Developed . . . . . . . . . .            0           0

</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Gas and Oil Reserve Quantities (Unaudited) - has been prepared using estimated
future production rates and associated production and development costs.
Continuation of economic conditions existing at the balance sheet date was
assumed.  Accordingly, estimated future net cash flows were computed by
applying prices and contracts in effect in December to estimated future
production of proved gas and oil reserves, estimating future expenditures to
develop proved reserves and estimating costs to produce the proved reserves
based on average costs for the year.  Average prices used in the computations
were: Gas (per Mcf) $2.19 in 1995, $2.29 in 1994 and $2.38 in 1993; Oil (per
barrel) $16.91 in 1995, $14.07 in 1994 and $11.73 in 1993.

Because reserve estimates are imprecise and changes in the other variables are
unpredictable, the standardized measure should be interpreted as indicative
of the order of magnitude only and not as precise amounts.


                                A-41
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Standardized Measure (in millions):                               1995             1994            1993
                                                                --------        ---------       ---------
<S>                                                            <C>              <C>             <C>
Future cash inflows. . . . . . . . . . . . . . . . .           $ 4,180.7        $ 3,101.1       $ 3,047.0
Future production and development costs. . . . . . .            (1,568.9)        (1,218.5)       (1,057.9)
Future income-tax expense. . . . . . . . . . . . . .              (539.1)          (499.3)         (528.0)
                                                               ---------        ---------       ---------
Future net cash flows. . . . . . . . . . . . . . . .             2,072.7          1,383.3         1,461.1
Less 10% annual discount . . . . . . . . . . . . . .               834.8            556.1           630.5
                                                               ---------        ---------       ---------
Standardized measure of discounted future net
  cash flows . . . . . . . . . . . . . . . . . . . .           $ 1,237.9        $   827.2       $   830.6
                                                               =========        =========       =========

Change in Standardized Measure (in millions):

Sales and transfers of gas and oil produced, net of
  production costs . . . . . . . . . . . . . . . . .           $  (151.4)       $  (120.8)      $  (136.2)
Changes in prices, net of production and future
  development costs. . . . . . . . . . . . . . . . .                63.1            (15.6)            (.5)
Extensions, discoveries and improved recovery,
  less related costs . . . . . . . . . . . . . . . .               175.8            121.3            41.4
Purchases of minerals in place . . . . . . . . . . .               367.6              1.6             9.4
Revisions of previous quantity estimates . . . . . .              (122.8)           (87.1)          (28.5)
Sales of minerals in place . . . . . . . . . . . . .               (22.9)            (1.3)
Accretion of discount. . . . . . . . . . . . . . . .               103.3            102.7           105.4
Net change in income taxes . . . . . . . . . . . . .                 7.6              5.1            20.9
Other. . . . . . . . . . . . . . . . . . . . . . . .                (9.6)            (9.3)           (1.0)
                                                               ---------         ---------      ---------
   Total . . . . . . . . . . . . . . . . . . . . . .           $   410.7         $   (3.4)      $    10.9
                                                               =========         =========      =========
</TABLE>



                                A-42
<PAGE>
<PAGE>
SUMMARY OF BUSINESS SEGMENTS
ENSERCH Corporation and Subsidiary Companies

The Corporation's major business segments are:
  Natural gas and oil exploration and production
  Natural gas pipeline & gathering, processing and marketing (GPM)
  Natural gas distribution
  Power and other

Through these business segments, the Corporation is engaged in (1) natural
gas and oil exploration and production - exploring for, developing, producing
and marketing natural gas and oil, (2) natural gas pipeline & GPM - owning and
operating interconnected natural gas transmission lines, underground storage
reservoirs, compressor stations and related properties, all within Texas;
gathering and processing natural gas to remove impurities and extract liquid
hydrocarbons for sale; and the wholesale and retail marketing of natural gas
in several areas of the U.S., (3) natural gas distribution - owning and
operating some 550 local gas utility distribution systems in Texas, and
(4) power and other -  developing, financing and operating electric power
generating plants and cogeneration facilities and operating thermal energy
plants for large building complexes, such as universities and medical centers.
<TABLE>
<CAPTION>
                                         Natural Gas
                                           and Oil
                                         Exploration Natural Gas                Power    General
                                             and       Pipeline   Natural Gas    and       and
                                          Production     & GPM   Distribution   Other     Other   Consolidated
                                         ----------- ----------- ------------  --------- -------- ------------
<S>                                        <C>        <C>           <C>        <C>       <C>        <C>
Revenues from Nonaffiliates
  1995 . . . . . . . . . . . . . .         $ 133,849  $  871,283    $ 886,291  $ 39,817  $          $1,931,240
  1994 . . . . . . . . . . . . . .            68,949   1,107,736      873,324    45,499              2,095,508
  1993 . . . . . . . . . . . . . .            79,780     784,035      966,452    48,635              1,878,902

Intersegment Revenues from
  Affiliates (eliminated
    in consolidation)
  1995 . . . . . . . . . . . . . .            87,002     125,168        1,174                          213,344
  1994 . . . . . . . . . . . . . .           110,191     128,027        1,383                          239,601
  1993 . . . . . . . . . . . . . .           110,016     123,934        1,424                          235,374

Operating Income (Loss)
  1995 . . . . . . . . . . . . . .           (11,450)     59,580       54,634     3,478    (8,513)      97,729
  1994 . . . . . . . . . . . . . .            25,617      27,048       38,334     5,761    (8,114)      88,646
  1993 . . . . . . . . . . . . . .           (37,293)     73,425       34,175     9,795   (11,865)      68,237

Depreciation and Amortization
  1995 . . . . . . . . . . . . . .           119,376      21,758       24,906     1,563       659      168,262
  1994 . . . . . . . . . . . . . .            79,594      22,888       22,475     1,403       619      126,979
  1993 . . . . . . . . . . . . . .           100,687      20,907       20,664     1,470       598      144,326

Identifiable Assets
  1995 . . . . . . . . . . . . . .         1,718,050     711,747      744,981    38,630   167,686(a) 3,381,094
  1994 . . . . . . . . . . . . . .         1,295,231     697,405      698,341    41,794   155,766(a) 2,888,537
  1993 . . . . . . . . . . . . . .         1,193,525     703,727      668,139    32,632   207,976(a) 2,805,999

Gross Additions to Property,
  Plant and Equipment
  1995 . . . . . . . . . . . . . .           190,168(b)   44,617       61,286       312       643      297,026
  1994 . . . . . . . . . . . . . .           133,254      47,503       78,186       622       493      260,058
  1993 . . . . . . . . . . . . . .           119,566      36,717       61,067       373       970      218,693
<FN>
(a)  Includes $74,051 in 1995, $62,622 in 1994 and $102,291 in 1993 related to discontinued operations.
(b)  Excludes property acquired in the purchase of DALEN.

Certain of the business segments provide services or sell products to one or more of the other segments.  Generally,
such sales are made at prices comparable with those received from nonaffiliated customers for similar products or
services.  Non-U.S. operations provided less than 10% of consolidated revenues and employed less than 10% of consolidated
assets for all periods presented.  No customer provided more than 10% of consolidated revenues.
</FN>
</TABLE>

                                A-43
<PAGE>
<PAGE>

QUARTERLY RESULTS (UNAUDITED) - The results of operations by quarters are
summarized below.  Quarterly amounts previously reported for 1994 and the
first quarter of 1995 have been restated to give effect to the pooling-of-
interests transaction with DGS. In the opinion of the Corporation's management,
all adjustments (consisting only of normal recurring accruals) necessary for a
fair presentation have been made.
<TABLE>
<CAPTION>

                                                                                   Quarter Ended
                                                               --------------------------------------------------------
                                                               March 31       June 30       September 30  December 31
                                                               ---------      --------      ------------  -----------
    <S>                                                        <C>           <C>             <C>            <C>
    1995:
      Revenues . . . . . . . . . . . . . . . . . . . . . .     $612,641      $396,160        $414,547       $507,892
      Operating Income (Loss). . . . . . . . . . . . . . .       67,532        (3,938)          4,114         30,021
      Net Income (Loss). . . . . . . . . . . . . . . . . .       30,816       (14,632)        (13,771)        10,640
      Earnings (Loss) Applicable to Common Stock . . . . .       27,780       (17,613)        (16,637)         7,833
      Per Share of Common Stock-
        Earnings (loss) applicable to common stock . . . .     $    .41      $   (.26)       $   (.24)      $    .11



1994:
   Revenues . . . . . . . . . . . . . . . . . . . . . .        $636,181      $409,962        $493,619       $555,746
   Operating Income (Loss). . . . . . . . . . . . . . .          71,235          (808)         (3,683)        21,902(a)
   Income (Loss) from Continuing Operations . . . . . .          35,330       (12,242)        (14,925)        73,289(a)(b)
   Income from Discontinued Operations. . . . . . . . .             562           743             399         18,938
   Net Income (Loss). . . . . . . . . . . . . . . . . .          35,892       (11,499)        (14,526)        92,227
   Earnings (Loss) Applicable to Common Stock . . . . .          33,048       (14,271)        (17,506)        89,204
   Per Share of Common Stock:
     Income (loss) from continuing operations after
       provision for dividends on preferred stock . . .        $    .48      $   (.22)       $   (.27)      $   1.03
     Discontinued operations. . . . . . . . . . . . . .             .01           .01             .01            .28
                                                               --------      --------        --------       --------
     Earnings (loss) applicable to common stock . . . .        $    .49      $   (.21)       $   (.26)      $   1.31

<FN>
(a)   Includes a $4.9 million after-tax ($7.6 million pretax) gain from the sale of an inactive offshore pipeline and
      facilities.
(b)   Includes a $70 million reduction of deferred income taxes associated with the reorganization of partnerships to form
      Enserch Exploration, Inc.
</FN>

Changes to previously reported information from pooling-of-interests transaction with
DGS

1995:
   Revenues . . . . . . . . . . . . . . . . . . . .            $ 64,740
   Operating Income . . . . . . . . . . . . . . . .                 990
   Income from Continuing Operations. . . . . . . .                 430

1994:
   Revenues . . . . . . . . . . . . . . . . . . . .            $ 70,479      $ 59,813        $53,893        $53,892
   Operating Income (Loss). . . . . . . . . . . . .                 326           (33)           452            452
   Income (Loss) from Continuing Operations . . . .                 (34)         (271)            41             41

</TABLE>

                                A-44
<PAGE>
<PAGE>

COMMON STOCK MARKET PRICES AND DIVIDEND INFORMATION

MARKET PRICES - ENSERCH COMMON STOCK


The Corporation's common stock is traded principally on the New York Stock
Exchange.  The following table shows the high and low sales prices per share
of the common stock of the Corporation reported in the New York Stock Exchange
- Composite Transactions report for the periods shown as quoted in The Wall
Street Journal.
<TABLE>
<CAPTION>

                                                 1995                     1994                       1993
                                         -------------------       ------------------        --------------------
                                          High          Low         High          Low         High           Low
                                         -------------------       ------------------         --------------------
            <S>                          <C>         <C>           <C>        <C>             <C>          <C>
            First Quarter . . . . .      $15 1/8     $12 5/8       $19 1/8    $12 7/8         $19 1/8      $14 1/8
            Second Quarter. . . . .       18 3/8      14 5/8        15 1/4     12 5/8          19 5/8       16 7/8
            Third Quarter . . . . .       18 5/8      15 7/8        16 1/2     13 1/8          22 5/8       17 1/2
            Fourth Quarter. . . . .       16 7/8      14 1/4        15         12 1/8          21 1/4       15 1/2

                                                 1992                     1991                        1990
                                         -------------------       -------------------        --------------------
                                          High          Low         High         Low          High           Low
                                         -------------------       ------------------         --------------------
            First Quarter . . . . .      $14 3/8     $10 3/8       $20 1/2    $16 7/8         $28          $23 3/8
            Second Quarter. . . . .       16 3/8      12 1/8        21 3/8     17 1/8          27 7/8       23
            Third Quarter . . . . .       16 1/8      14            18 3/4     15 5/8          28 1/8       24
            Fourth Quarter. . . . .       16 1/2      13 3/4        17 1/2     12 3/4          27 5/8       18 1/2
</TABLE>
<TABLE>
<CAPTION>

            COMMON STOCK DATA AT YEAR-END  1995        1994          1993        1992          1991        1990
                                          ------      ------        ------      ------        ------      ------
            <S>                           <C>         <C>           <C>         <C>           <C>          <C>
            Shareholders of Record        19,247      19,614        20,406      22,832        23,979       25,090
                                          ------      ------       ------       ------        ------       ------
            Shares Outstanding (000's)    68,516      68,158        67,860      67,238        66,506       65,968
                                          ------      ------        ------      ------        ------       ------
</TABLE>
DIVIDENDS PER SHARE OF COMMON STOCK

As of December 31, 1995, the Corporation had paid 206 consecutive quarterly
cash dividends on its common stock.  At December 31, 1995, $416 million of
common shareholders' equity was free of restrictions as to the payment of
dividends and redemption of capital stock.  The declaration of future
dividends will be dependent upon business conditions, earnings, cash
requirements and other relevant factors.  In February 1996, a quarterly cash
dividend of $.05 per share was declared, payable March 4, 1996, to
shareholders of record on February 23, 1996.  Quarterly cash dividends on
common stock were $.05 per share (annual rate of $.20 per share) in 1995
through 1993 and $.20 per share (annual rate of $.80 per share) for the three
preceding years.





                                A-45